STITES &HARBISONPLLC - Kentucky cases/2013-00475/20131220... · 2013-12-23 · 2.4 Forecast...

STITES &HARBISONPLLC ATTORNEYS

421 West Main Street Post Office Box 634 Frankfort, KY 40602-0634 [5021 223-3477 [502] 2234124 Fax www.stites.com

December 20, 2013

HAND DELIVERED

Jeff R. Derouen Executive Director Public Service Commission 211 Sower Boulevard P.O. Box 615 Frankfort, KY 40602-0615

RECPPVED

DEC2 0 2013

PUS

COMMISSION 6

Mark R. Overstreet (502) 209-1219 (502) 223-4387 FAX [email protected]

RE: Kentucky Power Company's Integrated Resource Planning Report

Dear Mr. Derouen:

Please find enclosed and accept for filing Kentucky Power Company's Integrated Resource Planning Report. It consists of four volumes. Volumes A-C are the redacted version of the report. The confidential information redacted from Volumes A-C is contained in Volume D, which is being filed with the Company's Motion for Confidential Treatment.

The Company is filing one unbound copy of Volumes A-D. It also is filing ten bound copies of Volumes A-C.

An index cross-referencing the provisions of the report to the applicable regulatory requirements is included in Chapter 1 (Volume A) of the report.

A copy of Volume D will be provided to those parties executing an appropriate non-disclosure agreement.

Finally, I enclose for the Commission's review and approval a copy of the text of the public notice required by 807 KAR 5:058, Section 10. By the Company's calculations, the notice must be submitted to the appropriate news agencies prior to January 10, 2014 to be published in accordance with the Commission's regulations.

Please do not hesitate to contact me if you have any questions.

Alexandria: VA Atlanta, GA Frankfort, KY Franklin, TN Jeffersonville, IN Lexington, KY Louisville, KY Nashville, TN

Very tru yo

Mark k. Overset cr •

Sr- LLC

ATTuRNszs

Jeff R. Derouen Executive Director December 20, 2013 Page 2

cc: Michael L. Kurtz (Volumes A-C) Dennis G. Howard (Volumes A-C) John Davies (Volumes A-C)

KENTUC POWER'

A unit of American Electric Power

RECEIVEE DEC 2 0 2013

PUBLIC SERVICE COMMISSION

INTEGRATED RESOURCE PLANNING REPORT TO THE

KENTUCKY PUBLIC SERVICE COMMISSION

Submitted Pursuant to Commission Regulation 807 KAR 5:058

VOLUME A

Case No. 2013-

December 20, 2013

;iiiii KENTUCKY POWER

A unit of American Electric Power 2013 Integrated Resource Plan

TABLE OF CONTENTS

VOLUME A

EXECUTIVE SUMMARY ES-1

1.0 OVERVIEW AND SUMMARY 1 1.1 General Remarks 2

1.1.1 Planning Process Summary 3 1.2 Planning Objectives 4 1.3 Company Operations 4 1.4. Load Forecasts 7

1.5 DSM Programs and Impacts 10 1.6 Supply-Side Resource Expansion 12

1.6.1 Kentucky Power Stand Alone 14 1.7 Significant Changes from the Previous IRP Filing 15 1.8 Financial Information 17 1.9 Next Steps, Key Issues/Uncertainties 18

1.9.1 Implementation Steps 18 1.9.2 Key Issues/Uncertainties 18

1.10 Cross Reference Table 22

2.0 LOAD FORECAST 29 2.1 Summary of Load Forecast 30

2.1.1 Forecast Assumptions 30 2.1.2 Forecast Highlights 30

2.2 Overview of Forecast Methodology 31 2.3 Forecast Methodology for Internal Energy Requirements 33

2.3.1 General 33 2.3.2 Short-term Forecasting Models 34

2.3.2.1 Residential and Commercial Energy Sales 34 2.3.2.2 Industrial Energy Sales 34 2.3.2.3 All Other Energy Sales 35

2.3.3 Long-term Forecasting Models 35 2.3.3.1 Supporting Models 36

2.3.3.1.1 Retail Natural Gas and Electricity Pricing Forecasts 36 2.3.3.1.2 Regional Coal Production Model 37

2.3.3.2 Residential Energy Sales 37 2.3.3.2.1 Residential Customer Forecasts 37 2.3.3.2.2 Residential Energy Usage Per Customer 37

2.3.3.3 Commercial Energy Sales 39 2.3.3.4 Industrial Energy Sales 40

2.3.3.4.1 Manufacturing 40

i

KENTUCKY POWER


2.3.3.4.2 Mine Power 40 2.3.3.5 All Other Energy Sales 40 2.3.3.6 Blending Short- and Long-Term Sales 41 2.3.3.7 Billed/Unbilled and Losses 41

2.4 Forecast Methodology for Seasonal Peak Internal Demand 42 2.5 Load Forecast Results 43

2.5.1 Load Forecast Including Approved EE Impacts (Base Forecast) 43 2.5.2 Load Forecast Excluding EE Impacts 43

2.6 Impact of Conservation and Demand-Side Management 44

2.7 Energy-Price Relationships 45

2.8 Forecast Uncertainty and Range Of Forecasts 47

2.9 Significant Changes from Previous Forecast 49 2.9.1 Energy Forecast 49 2.9.2 Peak Internal Demand Forecast 50 2.9.3 Forecasting Methodology 50

2.10 Additional Load Information 50

2.11 Data-Base Sources 51

2.12 Other Topics 51 2.12.1 Residential Energy Sales Forecast Performance 51 2.12.2 Peak Demand Forecast Performance 52 2.12.3 Forecast Updates 52 2.12.4 KPSC Staff Issues Addressed 52

2.13 Chapter 2 Exhibits 54

3.0 DEMAND-SIDE MANAGEMENT PROGRAMS 80

3.1 Kentucky Power Demand Reduction and Energy Efficiency Programs 81 3.1.1 Changing Conditions 81 3.1.2 Existing Programs 83

3.2 DSM Goals and Objectives 83

3.3 Customer & Market Research Programs 84

3.4 DSM Program Screening & Evaluation Process 85 3.4.1 Overview 85 3.4.2 Existing Program Screening Process 86

3.5 Evaluating DR/EE Impacts for Future Periods 87 3.5.1 Assessment of Achievable Potential 87

3.5.1.1 Consumer Programs 88 3.5.1.2 Smart Meters 90 3.5.1.3 Demand Response 90 3.5.1.4 Volt VAR Optimization (VVO) 92 3.5.1.5 Distributed Generation (DG) 93 3.5.1.6 Technologies Considered But Not Evaluated 93

3.5.2 Determining Expanded Programs for the IRP 94

ii

KENTUCKY ER


3.5.5 Evaluating Incremental Demand-Side Resources 98 3.5.6 Optimizing the Incremental Demand-side Resources 100 3.5.7 Expected Program Costs and Benefits 100 3.5.8 Discussion and Conclusion 102

3.6 Issues Addressed in KPSC Staff Report 103

3.7 Chapter 3, Appendix - DSM Program Descriptions 103

4.0 RESOURCE FORECAST 109

4.1 Resource Planning Objectives 110

4.2 Kentucky Power Resource Planning Considerations 110 4.2.1 General 110 4.2.2 Generation Reliability Criterion 110 4.2.3 Existing Pool and Bulk Power Arrangements 112

4.2.3.1 Interconnection Agreement 112 4.2.3.2 Transmission Agreement 112 4.2.3.3 PJM Membership 112

4.2.4 Environmental Compliance 113 4.2.4.1 Introduction 113 4.2.4.2 Air Emissions 113 4.2.4.3 Environmental Compliance Programs 114

4.2.4.3.1 Title IV Acid Rain Program 114 4.2.4.3.2 NOx SIP Call 115 4.2.4.3.3 Clean Air Interstate Rule (CAIR) 116 4.2.4.3.4 MATS Rule 116 4.2.4.3.5 NSR Settlement 117

4.2.4.4 Future Environmental Rules 119 4.2.4.4.1 Coal Combustion Residuals (CCR) Rule 119 4.2.4.4.2 Effluent Limitation Guidelines and Standards (ELG) 120 4.2.4.4.3 Clean Water Act "316(b)" Rule 120 4.2.4.4.4 National Ambient Air Quality Standards (NAAQS) 121 4.2.4.4.5 GHG Regulations 121

4.2.4.5 Kentucky Power Environmental Compliance 121

4.3 Procedure to Formulate Long-Term Plan 122 4.3.1 Develop Base-Case Load Forecast 122 4.3.2 Determine Overall Resource Requirements 122

4.3.2.1 Existing and Committed Generation Facilities 123 4.3.2.2 Retrofit or Life Optimization of Existing Facilities 123 4.3.2.3 Renewable Energy Plans 123 4.3.2.4 Demands, Capabilities and Reserve Margins —Going-in 124

4.3.3 Identify and Screen DSM Options 124 4.3.4 Identify and Screen Supply-side Resource Options 124

4.3.4.1 Capacity Resource Options 124 4.3.4.2 New Supply-side Capacity Alternatives 125 4.3.4.3 Baseload/Intermediate Alternatives 126

iii

KENTUCKY POWER


4.3.4.4 Peaking Alternatives 128 4.3.4.5 Renewable Alternatives 129

4.3.5 Integrate Supply-Side and Demand-Side Options 137 4.3.5.1 Optimize Expanded DSM Programs 138 4.3.5.2 Optimize Other Demand-Side Resources 138

4.3.6 Analysis and Review 138

4.4 Other Considerations and Issues 139 4.4.1 Transmission System 139

4.4.1.1 General Description 139 4.4.1.2 Transmission Planning Process 142 4.4.1.3 System-Wide Reliability Measure 143 4.4.1.4 Evaluation of Adequacy for Load Growth 143 4.4.1.5 Evaluation of Other Factors 144 4.4.1.6 Transmission Expansion Plans 145 4.4.1.7 Transmission Project Descriptions 145 4.4.1.8 FERC Form 715 Information 145 4.4.1.9 Kentucky Transmission Projects 147

4.4.2 Fuel Adequacy and Procurement 148

4.5 Resource Planning Models 150 4.5.1 Plexos° Model 150 4.5.2 Demand-Side Screening 151

4.6 Major Modeling Assumptions 151 4.6.1 Planning & Study Period 151 4.6.2 Load & Demand Forecast 152 4.6.3 Capacity Modeling Constraints 152 4.6.4 Wind RFI Evaluation and Assumptions 153 4.6.5 Commodity Pricing Scenarios 154

4.7 Modeling Results 159 4.7.1 Construction of the Preferred Portfolio 161 4.7.2 Preferred Portfolio summary 164

4. 8 Risk Analysis 166 4.8.1 Modeling Process & Results & Sensitivity Analysis 168 4.8.2 Sensitivity to CO2 Pricing 169

4.9 Kentucky Power Current Plan 170

4.10 IRP Summary 171

4.11 KPSC Staff Issues Addressed 172

4.12 Chapter 4 Exhibits 174

iv

ENTUCKY ER


REQUIRED APPENDICES

Volume B Chapter 2 Appendix

Book 1 of 3 Page 2 of 731 Book 2 of 3 Page 213 of 731 Book 3 of 3 Page 492 of 731

Volume C Chapter 2 Confidential Appendix (Redacted)

Volume D Confidential Supplement (Not Redacted)

Chapter 2 Appendix Exhibit 4-4 Exhibit 4-6 Exhibit 4-9 Exhibit 4-16 Exhibit 4-17

v

KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

LIST OF FIGURES Figure 1: Kentucky Power Service Territory 5 Figure 2: DSM Programs Costs and Savings 81 Figure 3: Participation in EE Programs Relationship to Measure Cost 82 Figure 4: Relationship of Incentive Percentage to Participation 89 Figure 5: Electric Energy Consumption Optimization 93 Figure 6: Distributed Generation Capital Costs 94 Figure 7: Residential and Commercial 2014 End-use in GWh 95 Figure 8: Current and Incremental End-use Program Target 96 Figure 9: Solar Dynamic Effects 97 Figure 10: Incremental Energy Savings Resources 101 Figure 11: United States Solar Power Locations 130 Figure 12: Solar Panel Installed Cost 131 Figure 13: Density of Solar Installation by County 132 Figure 14: Annual Electric Generating Capacity Additions by Fuel 133 Figure 15: Utility Wind Cost Assumption 135 Figure 16: United States Wind Power Locations 135 Figure 17: AEP CHP by End-use 137 Figure 18: Transmission Bulk Electric System Development 140 Figure 19: Commodity Prices 156 Figure 20: Kentucky Power Energy Position under Base Commodity Forecast 160 Figure 21: Kentucky Power Energy Position under High CO7 Commodity Forecast 160 Figure 22: Relationship between Expected Solar Costs and Utility value 162 Figure 23: Solar Production vs. Demand of Kentucky Power 163 Figure 24: Preferred Portfolio Distributed Solar Adoption Assumption 164 Figure 25: Variable Input Ranges 167 Figure 26: RRaR and Expected Value 169 Figure 27: Annual Impacts of CO2 Costs on Revenue Requirements 170

vi

KENTUCKY POWER


LIST OF TABLES Table 1: Resource Additions 3 Table 2: Peak Internal Demand and Energy Requirements Including Approved EE 8 Table 3: Peak Internal Demand and Energy Requirements Excluding Approved EE 9 Table 4: Kentucky Power Existing DSM Programs 12 Table 5: Summer Peak Going-In Reserve 13 Table 6: Winter Peak Going-In Reserve 14 Table 7: Financial Effects* 17 Table 8: DR Potential 92 Table 9: Incremental Demand-side Resources Cost Profiles 99 Table 10: VVO Cost Profile 99 Table 11: VVO Blocks 101 Table 12: EE Resource Costs 108 Table 13: DSM Program Costs Estimates 108 Table 14: NSR Consent Decree Annual (AEP) NO Cap 118 Table 15: Third Modification to the Consent Decree Annual (AEP) SO2 Cap 119 Table 16: Third Modification to the Consent Decree Annual SO2 Cap for Rockport Plant 119 Table 17: New Generation Technology Options 126 Table 18: Optimized Plans Summary Additions (2014-2028) 159 Table 19: Preferred Portfolio, Summary Additions (2014-2028) 165 Table 20: Long-Term Economic Summary 166 Table 21: Risk Factors and their Relationships 167

vii

MUMMY NER


2013 Integrated Resource Plan

EXECUTIVE SUMMARY

The Integrated Resource Plan (IRP or Plan) is based upon the best available information

at the time of preparation. However, changes that may impact this plan can, and do, occur

without notice. Therefore this plan is not a commitment to a specific course of action,

since the future is highly uncertain, particularly in light of the current economic

conditions, access to capital, the movement towards increasing use of renewable

generation and end-use efficiency, as well as current and future environmental

regulations, including proposals to control greenhouse gases. The implementation action

items as described herein are subject to change as new information becomes available or

as circumstances warrant.

An IRP explains how a utility company plans to meet the projected capacity (i.e.,

peak demand) and energy requirements of its customers. By Kentucky rule, Kentucky

Power Company (Kentucky Power or Company) is required to provide an IRP that

encompasses a 15-year forecast period (2014-2028). Kentucky Power's 2013 IRP has

been developed using the Company's current assumptions for:

• Customer load requirements — peak demand and energy;

• Commodity prices — coal, natural gas, on-peak and off-peak power prices,

capacity and emission prices;

• Supply-side alternative costs — including fossil fuel and renewable generation

resources; and

• Demand-side program costs and analysis.

As shown in its 2013 IRP, Kentucky Power has a plan to provide adequate supply

and demand resources to meet its peak load obligations for the next fifteen years. The key

components of this plan are for Kentucky Power to:

• Transfer a 50% undivided ownership interest of the Mitchell Plant (780 MW)

from affiliate Ohio Power Company (OPCo) to Kentucky Power, to replace

the 800 MW Big Sandy Unit 2 which is scheduled to retire in 2015 (Mitchell

Transfer);

• Convert Big Sandy Unit 1 (278 MW) to burn natural gas instead of coal;

ES-1

KENTUCKY ER

A unit ol American Electric Power 2013 Integrated Resource Plan

o Continue to purchase power from the Rockport Units;

® Make increased investment in demand-side management; and

• Purchase the output of the 58.5 MW ecoPower Hazard, LLC' (ecoPower)

biomass plant starting in 2017.

Additionally, Kentucky Power considered the purchase of 100 MW of wind

power as part of this IRP process and as a result of the evaluation performed, may pursue

a Purchase Power Agreement (PPA) for wind power for delivery beginning in 2015.

Kentucky Power evaluated other supply- and demand-side measures and, as a result,

expects that utility-scale solar resources will become economically justifiable by 2020

and that customer-owned solar generation will begin to be economical to customers prior

to that, further reducing the requirements for new utility-owned generation. At the same

time, these 'non-traditional' resources will provide the Company with much-needed

energy resources.

Environmental Compliance Issues

The 2013 IRP considers final and proposed future U.S. Environmental Protection

Agency (EPA) regulations that will impact fossil-fueled electric generating units (EGU).

The analyses used in developing this IRP assume that greenhouse gas (GHG)

legislation or regulation on existing units will eventually be implemented. However,

rather than a more comprehensive cap-and-trade approach, it is assumed that the resulting

impact would be in the form of a carbon dioxide (CO2) "tax" which would take effect

beginning in 2022. The cost of CO? emissions is expected to stay within the $15-

$20/metric ton range over the long-term analysis period.

As approved by the Kentucky Public Service Commission (Commission) in Case No. 2013-00144 by Order dated October 10, 2013

ES-2

ENTUCIiY ER


Summary of Kentucky Power Resource Plan

Kentucky Power's total internal energy requirements are forecasted to increase at

an average annual rate of 0.1% over the IRP planning period (2014-2028). Kentucky

Power's corresponding summer and winter peak internal demands are forecasted to grow

at average annual rates of 0.3% and 0.1%, respectively, with annual peak demand

expected to continue to occur in the winter season through 2028.

To determine the appropriate level of additional demand-side, distributed, and

renewable resources, Kentucky Power utilized the Plexos® Linear Program (LP)

optimization model to develop a "least-cost" resource plan. Although the IRP planning

period is limited to 15 years (through 2028), the Plexos® modeling was performed

through the year 2040 so as to properly consider various cost-based "end-effects" for the

resource alternatives being considered.

As a result of the modeling, and taking into account the Stipulation and

Settlement Agreement surrounding the Mitchell Transfer, et al (Mitchell Settlement

Agreement)', Kentucky Power developed a Preferred Portfolio. To arrive at the

Preferred Portfolio composition, Kentucky Power developed Plexos -derived,

"optimum" portfolios under five commodity price forecasts. The Preferred Portfolio is

intended to provide the lowest reasonable cost of (peak) demand and energy to Kentucky

Power's customers while meeting environmental and reliability constraints and reflecting

emerging preference for, and the viability of customer self-generation. This portfolio:

• Receives 50% of the Mitchell Plant in 2014.

• Retires Big Sandy Unit 2 in 2015.

• Converts Big Sandy Unit 1 to natural gas fired operation in 2016.

• Assumes the addition of 100 MW of wind energy from a Federal Production

Tax Credit (PTC) eligible wind project beginning in 2015.

• Implements customer and grid energy efficiency (EE) programs so as to

2 As approved by the Commission in Case No. 2012-00578, by Order dated October 7, 2013.

ES-3

Kentucky Power 2014 Capacity Kentucky Power 2028 Capacity Solar

05 EE Gas

Biomass 0% 1% Solar Wind

3% 0% Biozss

Wind 0%

Figure ES-lb Kentucky Power Energy Production Changes

Kentucky Power 2014 Generation Efficiency../

..---Sc Ot 16. Biomass

0%

Kentucky Power 2028 Generation Solar r Blomass

Wind 356 / 5% Efficiency 4%

3%

Wind 0%

KENTUCKY POWER' A unit of American Electric Power


reduce energy requirements by 260 GWh (or 4% of projected energy needs)

by 2028.

• Purchases the output of the 58.5 MW ecoPower biomass plant beginning in

2017.

• Adds utility-scale solar beginning in 2020; total solar capacity reaches 90

MW (nameplate) in 2028.

• Recognizes additional distributed solar capacity will be added by customers,

starting in 2016, of about 3 MW (nameplate) and ramping up to about 41 MW

(nameplate) by 2028.

Specific Kentucky Power capacity and energy production changes over the

forecast period associated with the Preferred Portfolio are shown in Figures ES-la and

ES-lb, respectively, and their relative impacts to Kentucky Power's capacity and energy

position are shown in Figures ES-2a and ES-2b respectively.

Figure ES-la Kentucky Power PJM Capacity Changes

ES-4

= KENTUCKY POWER" A unit of American Electric Power 2013 Integrated Resource Plan

Figures ES-la and ES-lb indicate that this Preferred Portfolio would reduce

Kentucky Power's reliance on coal-based generation as part of its portfolio of resources,

thereby enhancing fuel diversity. Specifically, the Company's capacity mix attributable to

coal-fired assets would decline from 99% -to- 71% over the planning period. Gas assets

and renewables increase from 0% -to- 16% and 1% -to- 13% repectively over the planning

period. Similarly, Kentucky Power's energy mix attributable to fossil-based generation

would comparably decrease from 99% -to- 85% over the period. The Preferred Portfolio

highlights the fact that, while the Company may appear to have more than ample capacity

to reliably meet the needs of its customers, without the addition of "energy resources", it

would not be long from an energy perspective at all times. Moreover, the layers of non-

traditional energy resources being added as part of this planning process would serve to

hedge Kentucky Power's exposure to (PJM) energy market volatility, producing a lower-

risk solution than one that relies on market purchases.

Figure ES-2a Kentucky Power PJM Capacity Position3

2000

1800

1600

A' 1400 ri o_ 1200 m

(...) 2 1000

2-1.- 800

2 600

400

200

0

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

MINI Coal MIN Gas MIMI Biomass IMM Solar IMES Wind MIN EE -Total UCAP Obligation

3 Capacity position, and the underlying peak demand forecast,"transition" reflected in the 2017/18 PJM Planning Year (2017) is largely a function of utilizing PJM's own estimate of AEP Zonal peak demand allocated to Kentucky Power through the 2016/17 Planning Year (2016), then shifting to AEP's (lower) estimate of a stand-alone Kentucky Power peak demand (diversified to be coincident with PJM peak) thereafter.

ES-5

9,000

8,000

7,000

6,000

c 5,000 0

4,000

2 3,000

2,000

1,000

0

KENTUCKY POWER'



Figure ES-2b Kentucky Power Energy Position

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

Fossil Wind

Emma Biomass Solar

Efficiency Forecast

The following Table ES-1 provides a summary of the Preferred Portfolio

resource optimization modeling under the base case commodity pricing scenario:

ES-6

Kentucky Power Company 2013 Integrated Resource Plan

Cumulative Resource Changes (2014-2028)

IRP

Yr.

PJM

Plan YeariAl

Preferred Portfolio

Cumul.

NET

CHANGE MW

Resulting Kentucky Power

PJM Reserve

Margin

(Cumulative)

RETIREMENT S / DERATES

Fossil Mitchell

Transfer

(Cumulative) RESOURCE ADDITIONS

Biomass DSM VVind19 Solar`l

(Cumulative)

NAMEPLATE ADDITIONS

Wind Solar

Existinge New EE VVO Distributed Utility-Scale Distributed Utility-Scale MW MW MW MW MW MW MW MW MW MW MW MW

1 201415 - 780 - 5 1 4 0 0 0 791 64.6% m 0 0 0 2 2015M (800) (c) 780 7 3 4 13 0 0 8 20.6% 100 0 0 3 201601 (810) 101 780 - 9 5 4 13 1 0 2 19.7% 0} 100 3 0 4 2017 (810) 780 59 10 6 4 13 1 0 63 402% 100 3 0 5 2018 (810) 780 59 11 7 4 13 2 0 66 40.8% 100 4 0 6 2019 (810) 780 59 12 10 4 13 2 0 69 41.0% 100 5 0 7 2020 (810) 780 59 12 14 4 13 3 4 79 422% 100 7 10 8 2021 (810) 780 59 13 17 8 13 3 8 90 42.6% 100 8 20 9 2022 (810) 780 59 13 17 8 13 4 11 95 42.4% 100 11 30

10 2023 (810) 780 59 14 17 8 13 5 15 101 42.8% 100 13 40 11 2024 (810) 780 59 14 21 8 13 6 19 110 43.5% 100 17 50 12 2025 (810) 780 59 14 23 8 13 8 23 117 43.1% 100 21 60 13 2026 (810) 780 59 14 25 8 13 10 27 125 43.4% 100 26 70 14 2027 (810) 780 59 14 27 8 13 12 30 133 43.4% 100 33 80 15 2028 (810) 780 59 14 23 8 13 16 34 136 432% 100 41 90

44

131 TOTAL DSM

TOTAL Solar Ing PIM Planning Year is effective June 1.

M Kentucky Power collectively-participated with affilated AEP-East operating companies in these established PJM (Capacity) Planning Years, electing the Fixed Resource Requirement (FRR) ('self,)planning option through the 2016 PJM Planning Year. For purposes of this IRP only, beginning with the 2017 Planning Year Kentucky Power is assumed to be a 'stand-alone' entity.

} Big Sandy Plant (Unit 2) retirement effective approximately June 1, 2015, concurrent with implementation of U.S. EPA Mercury and Air Toxics Standards (MATS) Rules.

M Big Sandy Plant (Unit 1) gas conversion derate

'9 Represents estimated contribution from current/known Kentucky Power program activity reflected in the Company's load and demand forecast; All incremental impacts are included as "resources" outside of the load forecast

In Due to the intermittency of wind resources, PJM initially recognizes 13% of wind resource 'nameplate' MW rating for ICAP determination purposes.

151 Due to the intermittency of solar resources, PIM initially recognizes 38% of solar resource 'nameplate' MW rating for ICAP determination purposes. Note: Totals may reflect rounding

KENTUGisil POWER


Table ES-1

1112.1. 010.466.

ES-7

MTUCKY NER'


Conclusion

This IRP provides for reliable electric utility service, at reasonable cost, through a

combination of supply-side resources, renewable supply- and demand-side programs.

Kentucky Power will provide for adequate capacity resources to serve its customers' peak

demand and required PJM Interconnection, LLC (PJM) reserve margin needs throughout

the forecast period.

Moreover, this IRP will serve to also recognize Kentucky Power's even more-

pressing energy position prospectively. The highlighted Preferred Portfolio offers

incremental resources that will provide—in addition to the needed PJM installed capacity

(ICAP) to achieve mandatory PJM (summer) peak demand requirements—additional

energy so as to protect the Company's customers from being exposed to PJM energy

markets that could be influenced by many external factors, including the impact of

carbon, going-forward.

The IRP process is a continuous activity; assumptions and plans are continually

reviewed as new information becomes available and modified as appropriate. Indeed, the

capacity and energy resource plan reported herein reflects, to a large extent, assumptions

that are subject to change; it is simply a snapshot of the future at this time. This IRP is

not a commitment to a specific course of action, as the future is highly uncertain. The

resource planning process is becoming increasingly complex when considering pending

regulatory restrictions, technology advancement, changing energy supply pricing

fundamentals, uncertainty of demand and EE advancements. These complexities

necessitate the need for flexibility and adaptability in any ongoing planning activity and

resource planning processes. Lastly, the ability to invest in extremely capital-intensive

generation infrastructure is increasingly challenged in light of current economic

conditions and the impact of all these factors on Kentucky Power's customers will be a

primary consideration in this report.

ES-8

KENTUCKY POWER A unit of American Electric Power


1.0 OVERVIEW AND SUMMARY

1

KENTUCKY POWER


1.1 General Remarks

The AEP-East utilities that own generation4 have for decades operated as part of

the AEP integrated public utility holding company system under the now-repealed Public

Utility Holding Company Act of 1935. As part of that arrangement, those companies

coordinated the planning and operations of their respective generating resources pursuant

to the AEP Interconnection Agreement (Pool or Pool Agreement).5

On December 17, 2010, in accordance with Section 13.2 of the Pool Agreement,

each of the Pool members provided notice to the other members (and to American

Electric Power Service Corporation (AEPSC), as agent) to terminate the Pool Agreement

(which includes the Interim Allowance Agreement (IAA)), on January 1, 2014. As a

result, effective January 1, 2014, Kentucky Power will be responsible for its own

generation resources and will need to maintain an adequate level of power supply

resources to individually meet its own load requirements for capacity and energy,

including any required reserve margin.6

This IRP document presents a plan for Kentucky Power to meet its obligations as

a stand-alone company. Pursuant to that Plan, Table 1 shows the Company's resource

additions and reductions for the period 2014-2028. This includes the addition of a 50

4 Kentucky Power, Appalachian Power Company (APCo), Indiana Michigan Power Company (I&M), and OPCo. 5 The Pool Agreement, which has been amended several times, is on file with the Federal Energy Regulatory Commission (FERC) as Rate Schedule No. 11). 6 Three of the current Pool Members — Kentucky Power, APCo, and I&M —together with AEPSC, have agreed to participate under a new arrangement ("the Power Coordination Agreement (PCA)"), which provides the opportunity for the members to collectively participate in the organized power markets of a regional transmission organization and provides an off-system sales allocation methodology. Kentucky Power, APCo, and I&M together with OPCo and affiliate AEP Generation Resources have agreed to enter into an interim arrangement (the Bridge Agreement) to provide for the allocation of the cost of meeting pre-existing PJM Fixed Resource Requirement (FRR) capacity obligations and settling existing marketing and trading positions that will survive termination of the Pool Agreement. Additional information regarding the PCA and the Bridge Agreement as they pertain to Kentucky Power can be found in FERC Docket No. ER13-234. These proposed agreements have been submitted to FERC.

2

Kentucky Power Company

2013 Integrated Resource Plan Cumulative Resource Changes (2014-2025)

Preferred Hof-Paso

(Cumulative)

RETIREMENT (Cumulative) RESOURCE ADDITIONS

Resu1ing

Kentucky S / DERATES Cumul. Power

RP PJM Fossil t.il ite iii ell Biomass 05M Wield "I S NET PJM Reserve

Yr. Plan Year. fe Existing— New EC V U Dlseebived Utilay-Scale CHANGE Margin MW MW MW MW MW MW MW MW MW

2014. 750 5 1 0 0 0 791 646% 2

3

201511

20161'1

(50a) IS/

(810) fel 750

780 7 3

- 9 5

13 0 13 t

o 0

5

2

206% el

19,7% tel

4 2017 (810) 780 59 10 6 13 1 0 63 402% 5 2018 (810) 780 59 11 7 13 2 0 66 40,8%

2019 (510) 780 59 12 10 13 2 0 69 41,0% 7 2020 (510) 780 59 12 14 13 3 4 79 42.2%

2021 (810) 780 59 13 17 13 3 8 90 42E% 2022 (510) 750 59 13 17 13 4 11 95 414%

1 0 2023 (510) 780 59 14 17 13 5 15 101 42 5% 1 1 2024 (810) 780 59 14 21 13 5 19 110 435% 12 2025 (810) 780 59 14 23 13 5 23 117 43,1% 13 2026 (510) 750 59 14 25 13 10 27 125 43.4% 14 2027 (510) 750 59 14 27 13 12 30 133 43.4% 15 2025 (510 780 59 14 23 13 16 34 136 432%

(Cumulative)

NA8eip! 4 TF ADDITIONS

Wind

Solar

tneuteril Ut

MW MW MW 0 0 a 100 0 0 100 3

100 3 0

100 4 0

100 5 0

100 7 10 100 5 20 100 11 30 100 13 40 100 17 50 100 21 60 100 26 70 100 33 BO 100 41 90

44 TOTAL OS M

131

TOTAL Solar 161 00,1 Planning Year Is Weal/rerun,

Power betlectIselosparticIpared with of Noted efER/East operating companies in these established PIM ICa Fladiri Planning Vears, electingthe Fixed Resource Requirement IFRR1('sele-iplaneing eptlen through the 2016 PJM Planning Year. ',purposes of tiffs friP only, beginning with the 2617 Planning veer Nentucky Rawer Is assumed to be a 'stand/aloe& emit,

11 Bigeantlg Rlveilvmr 11 retirement effective approximately lune 1, 70[5, concurrent with Imtderueo1aUon of 00. 6,,,crsorboad pr TOxles 5tondards laurel e&ee

1 6/R2w/4 Plantlnnir 116as conversion dcbafb 16 Represents estimated contdb000n from curl erg/known Oenlocky rower program activity reOected in the Company's load and demand forecast:AB Incremental impacts are included as resource, outside of the load forecast

'Duet° the Intermittency of Mod resources/PM initially rodoBoltet Pat of 'pit'MW e U 1COR deter.oaRo, Pcf Pot es/

l'1 Doe to the Intermittency of solar resources, 67,14:Wally recognises SP% of solar resource lnaloRP1o1o1S/SW rating for 16R, de1.001eadoe Remote, Note: relate ',reflect rounding

La; KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

percent ownership share of the Mitchell units in 2014; retirement of Big Sandy Unit 2 in

2015; conversion of Big Sandy Unit 1 to gas-fired operation in 2016; a 58.5 MW biomass

resource in 2017; a potential 100 MW (nameplate) wind resource in 2015; the

incorportation of incremental levels of demand-side management EE resources; as well

as the eventual introduction of small amounts of solar resources over the planning period.

Such solar resources taking the form of both (centralized) utility-scale solar and

customer-elected distributed solar.

Table 1: Resource Additions

1.1.1 Planning Process Summary

The recommended plan provides the lowest practical cost solution through a

combination of traditional supply, renewable, and demand-side investments. The

tempered load growth combined with additional renewable resources and other additional

supply-side resources, and increased DR/EE initiatives reduce the need for new capacity

until beyond the end of the IRP forecast period (2028). Kentucky Power is expected to

have adequate resources to serve its customers' requirements throughout the forecast

period. Section 1.6.1, provides an analysis of Kentucky Power's stand-alone position for

the forecast period.

3

;lila KENTUCKY POWER


The planning process is a continuous activity, assumptions and plans are

continually reviewed as new information becomes available and modified as appropriate.

Indeed, the capacity and energy resource plan reported herein reflects, to a large extent,

assumptions that are subject to change; it is simply a snapshot of the future at this time.

This IRP is not a commitment to a specific course of action, as the future is highly

uncertain. The resource planning process is becoming increasingly complex when

considering pending regulatory restrictions, technology advancement, changing energy

supply pricing fundamentals, uncertainty of demand and EE advancements. These

complexities necessitate the need for flexibility and adaptability in any ongoing planning

activity and resource planning processes. Lastly, the ability to invest in extremely capital-

intensive generation infrastructure is increasingly challenged in light of current economic

conditions and the impact of all these factors on Kentucky Power's customers will be a

primary consideration in this report.

1.2 Planning Objectives

(807 KAR 5:058 Sec. 5.1)

The primary objective of power system planning is to assure the reliable,

adequate and economical supply of electric power and energy to the consumer, in an

environmentally compatible manner. Implicit in this primary objective are related

objectives, which include, in part: (1) maximizing the efficiency of operation of the

power supply system, and (2) encouraging the wise and efficient use of energy.

Other objectives of a resource plan include planning flexibility, creation of an

optimum asset mix, adaptability to risk and affordability. In addition, given unique

impact on generation of environmental compliance, the planning effort must be in concert

with anticipated long-term requirements as established by the environmental compliance

planning process.

1.3 Company Operations

Kentucky Power serves 173,000 retail customers in a 3,762 square-mile area in

eastern Kentucky (See Figure 1). There is a population of 429,000 in counties served by

Kentucky Power in whole or partially. The principal industries served are primary metals,

4

OC SANDY PLANT

KENTUCKY POWER


chemicals and allied products, petroleum refining and coal mining. The Company also

sells and transmits power, at wholesale, to two Kentucky municipalities; the City of

Olive Hill and the City of Vanceburg.

Figure 1: Kentucky Power Service Territory

Kentucky Power's internal load usually peaks in the winter; the all-time peak

internal demand of 1,678 megawatts (MW) occurred on January 25, 2008. On August 24,

2007, an all-time summer peak internal demand of 1,358 MW was experienced. Of

Kentucky Power's total internal energy requirements in 2012, which amounted to 7,155

gigawatt-hours (GWh), residential, commercial, and industrial energy sales accounted for

31.3%, 18.9%, and 42.8%, respectively. Public street and highway lighting, sales for

resale, and all other categories accounted for the remainder.

As of December 2013, Kentucky Power owns and operates the 1,078 MW, coal-

fired Big Sandy Plant, consisting of an 800-MW unit and a 278-MW unit, at Louisa,

Kentucky, and has a unit power agreement with AEP Generating Company (AEG), an

affiliate, to purchase 393 MW of capacity from the Rockport Plant, located in southern

Indiana, through December 7, 2022, which is the end of the purchase agreement period.7

For purposes of the development of this long-term IRP, however, it has been assumed

5

Li1;; KENTUCKY milm POWER



that this purchase agreement would be extended beyond the end of the planning period.

Lastly, Kentucky Power will also own a 780 MW share of the Mitchell Plant Units 1 and

2, located at Captina, West Virginia, beginning January 1, 2014.

The AEP System's generating eastern operating companies, including Kentucky

Power, are electrically interconnected by a high capacity transmission system extending

from Virginia to Michigan. This eastern transmission system, consisting of an integrated

765-kV, 500-kV, and 345-kV, extra-high-voltage (EHV) network, together with an

extensive underlying 138-kV transmission network, and numerous interconnections with

neighboring power systems, is planned, constructed, and operated to provide a reliable

mechanism to transmit the electrical output from the AEP System—East Zone generating

plants to the principal load centers and to provide open access transmission service

pursuant to FERC Order No. 888.

AEP transferred functional control of transmission facilities in the Eastern part of

its system to the PJM Interconnection, LLC, a regional transmission organization (RTO)

in 2004. This transfer was approved by the Kentucky Public Service Commission in Case

No. 2002-00475 order dated May 19, 2004. The PJM RTO assumed the monitoring,

market operations and planning responsibilities of these facilities. In addition, PJM

assumed the Open Access Same Time Information System (OASIS) responsibility

including the evaluation and disposition of requests for transmission services over the

AEP System—East Zone transmission system. PJM also became the North American

Electric Reliability Council (NERC) Reliablity Coordinator for the AEP System-East

Zone transmission system. AEP-East continues to maintain and physically operate all of

its transmission facilities. AEP-East retains operational responsibility for those facilities

that are not under PJM functional control, and is involved in the various operations, and

planning stakeholder processes of PJM. In addition, PJM directs the dispatch of the AEP

7 The purchase agreement calls for Kentucky Power to acquire 30% of AEG's 50% share of both Units 1 (1,320 MW) and Unit 2 (1,300 MW)

KENTUCKY WER


System-East Zone generating resources to meet minute-to-minute loads and determines

the planning reserve required to maintain generation resource adequacy.

1.4. Load Forecasts

(807 KAR 5:058 Sec. 5.2.,5.3., and 5.4.)

It should be noted that the load forecasts presented herein began development in

early 2013 and were finalized in July 2013 and, therefore, do not reflect the experience

for the summer season of 2013 and later, or other relevant changes.8

Kentucky Power's forecasts of energy consumption for the major customer

classes were developed using both short-term and long-term econometric models. These

energy forecasts were determined in part by forecasts of the regional economy, which, in

turn, are based on the December 2012 national economic forecast of Moody's Analytics.

The forecasts of seasonal peak demands were developed using an analysis of energy and

load shapes that estimates hourly demand.

Some of the key assumptions on which the load forecast is based include:

• moderate economic growth;

• slow growth in energy prices;

• generally slow decline in the Company's service-area population; and

• normal weather.

Table 2 provides a summary of the "base" forecasts of the seasonal peak internal

demands and annual energy requirements for Kentucky Power for the planning years

2014 to 2028. The forecast data shown on this table reflects adjustments for filed EE

programs. In addition, inherent in the forecast are the impacts of past customer

8The load forecasts (as well as the historical loads) presented in this report reflect the traditional concept of internal load, i.e., the load that is directly connected to the utility's transmission and distribution system and that is provided with bundled generation and transmission service by the utility. Such load serves as the starting point for the load forecasts used for generation planning. Internal load is a subset of connected load, which also includes directly connected load for which the utility serves only as a transmission provider. Connected load serves as the starting point for the load forecasts used for transmission planning.

7

flf Li KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

conservation and load management activities, including demand-side management

(DSM) programs already in place.

Table 2: Peak Internal Demand and Energy Requirements Including Approved EE

Table 2 Kentucky Power Company

Forecast of Peak Internal Demand and Energy Requirments Including Approved Energy Efficiency Impact

2014-2028

Peak Intel nal Demand

Winter Internal Summer Following Energy Req'ts

Year (MW) (MW) (GWh)

2014 1,132 1,431 6,958 2015 1,133 1,432 6,953 2016 1,134 1,431 6,970 2017 1,137 1,431 6,975 2018 1,139 1,432 6,979 2019 1,141 1,430 6,986 2020 1,142 1,436 6,997 2021 1,149 1,439 7,012 2022 1,154 1,438 7,036 2023 1,157 1,438 7,056 2024 1,158 1,444 7,072 2025 1,166 1,448 7,090 2026 1,171 1,452 7,112 2027 1,176 1,454 7,134 2028 1,179 1,459 7,158

°A Average Growth rate, 2014-2028 0.3 0.1 0.1

Note: Kentucky Power interrup ible load is assumed to be not available for interruption at the time of the seasonal peaks

As Table 2 indicates, during the period 2014-2028, Kentucky Power's base

internal energy requirements are forecasted to increase at an average annual rate of 0.1%,

while the corresponding summer and winter peak internal demands are forecasted to

grow at average annual rates of 0.3% and 0.1%, respectively. Kentucky Power's annual

peak demand is expected to continue to occur in the winter season. However, as a

member of PJM, Kentucky Power is only obligated to plan to meet its summer peak

given that PJM is, itself, summer peaking.

v11; KENTUCKY mom POWER



Table 3 shows Kentucky Power's load forecast information as in Table 2 except

that the peak demands and energy requirements have been increased, where appropriate,

to exclude the impact of the approved EE Kentucky programs assumed to be

implemented during the forecast period. A comparison of the data shown on Tables 2 and

3 indicates that the approved EE program effects are relatively minor and do not

significantly affect the long-term load growth rates.

Table 3: Peak Internal Demand and Energy Requirements Excluding Approved EE

Table 3 Kentucky Power Compnay

Forecast of Peak Internal Demand and Energy Requirments Excluding Approved Energy Efficiency Impact

2014-2028

Peak Internal Demand

Winter Internal Summer Following Energy Req'ts

Year (MW) (MW) (GWh)

2014 1,137 1,442 7,004 2015 1,140 1,445 7,014 2016 1,143 1,447 7,043 2017 1,147 1,448 7,056 2018 1,150 1,450 7,066 2019 1,153 1,449 7,077 2020 1,155 1,456 7,092 2021 1,162 1,460 7,108 2022 1,167 1,459 7,133 2023 1,170 1,459 7,154 2024 1,172 1,465 7,169 2025 1,179 1,470 7,187 2026 1,185 1,474 7,209 2027 1,190 1,475 7,231 2028 1,193 1,480 7,255

Average Growth rate, 2014-2028 0.3 0.2 0.2

Note: Kentucky Power interruptible load is assumed to be not available for interruption at the time of the seasonal peaks



1.5 DSM Programs and Impacts

(807 KAR 5:058 Sec. 5.4)

Kentucky Power has offered a variety of conservation and DSM programs since

1994 that are designed to encourage customers to use electricity efficiently, achieve

energy conservation, and reduce the level of future peak demands for electricity.

Kentucky Power greatly expanded its EE programs in 2010 and now offers 12 programs

for its residential and commercial customers. From 2008 through 2013, these programs

have installed efficiency measures that are saving Kentucky customers approximately 48

GWh annually. Kentucky Power will continue to benefit from the load impacts from

these traditional DSM programs for many years. These load impacts are "embedded" in

the base load forecast of the integrated resource plan. Additionally, Kentucky Power

continues to provide peak demand options such as time-of-day tariffs.

Since Kentucky's last IRP, the EE landscape has changed dramatically. First and

foremost, the provisions of the Energy Independence and Security Act of 2007 (EISA

2007) are nearly fully phased in, limiting the impacts of utility lighting programs,

prospectively. Lighting programs have constituted the bulk of energy savings for

Kentucky programs and programs nationwide.

EISA 2007 requires that screw-in lighting be 25% more efficient than traditional

incandescent lights by the end of 2013, which has resulted in the typical 100, 75, and 60

watt incandescent light bulbs being phased out. Compact Fluorescent Lamp (CFL) bulbs,

as part of an EE program, may still represent savings over the increased standard, as there

are some substitutes, notably, efficient halogens. However, by year-end 2019, the

standard increases to preclude any substitutes, and the CFL bulb becomes the de facto

standard. Similarly, the commercial T-12 light has been prohibited from manufacture or

import since mid-2012. Replacing T-12 lights with T-8 lights has constituted the bulk of

commercial lighting programs nationwide but eventually, as old stock is consumed, will

no longer be considered as an option for utility lighting programs. The long-term load

forecast recognizes this and assumes all lighting will be at the mandated standards. This

makes any energy savings associated with traditional lighting programs short-lived, as

they become implicit in the load forecast.

10

► KENTUCKY POWER



Further expansion of Kentucky's programs or development of new programs must

reflect this evolution. It is unrealistic to expect energy savings associated with lighting

programs of the past to translate to prospective programs with substantially non-lighting

measures.

The Company has been continually working with the Kentucky Power DSM

Collaborative (which was established in November 1994 to develop Kentucky Power's

DSM plans) to ensure that DSM programs are implemented as effectively and efficiently

as possible and are helping Kentucky customers save energy. Over the years, the

Kentucky Power DSM Collaborative has worked closely in reviewing, recommending

and endorsing DSM programs for Kentucky Power customers. Through continuously

monitoring the program performance, program participation level and DSM market

potential, the Collaborative has recommended the addition, deletion and modification of

various DSM programs. The development of Kentucky Power's DSM programs by the

Collaborative incorporated the Collaborative's perspectives on those aspects of integrated

resource planning that related to demand-side management.

Table 4 lists the existing DSM programs that are currently being offered in

Kentucky.

EE programs are included in this IRP in one of two ways: current, approved

programs that are expected to continue through the forecast period by way of the impacts

of those programs being included in the load forecast; and incremental demand-side

programs which were evaluated with all other resource options and included in the plan,

if warranted.

11

Limili f KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

Table 4: Kentucky Power Existing DSM Programs

Kentucky Power

Existing DSM Programs

1. Targeted Energy Efficiency Program 2. High Efficiency Heat Pump -Mobile Home Program, 3. Mobile Home New Construction Program 4. Modified Energy Fitness Program 5. High Efficiency Heat Pump Program 6. Energy Education for Students Program 7. Community Outreach Compact Fluorescent Lighting (CFL) Program 8. Residential HVAC Diagnostic and Tune-up 9. Residential Efficient Products 10. Small Commercial HVAC Diagnostic Tune-up 11. Small Commercial High Efficiency Heat Pumpm/Air Conditioner 12. Commercial Incentive

1.6 Supply-Side Resource Expansion

(807 KAR 5:058 Sec. 5.4.)

In the planning process, several considerations impact Kentucky Power's

assessment of supply-side resources, namely:

• age of the fossil-fueled generation fleet;

• impact of final and proposed future EPA regulations, state legislated

renewable portfolio standards (RPS) and voluntary Clean Energy Goals;

• current mix of capacity which relies heavily on baseload generating assets;

and

• availability and cost of alternative assets including utility-scale solar and

wind.

These factors provide both objective and subjective data that play into the

construction of Kentucky Power's ultimate, Preferred Portfolio. In summary, the

following represent going-in supply-side resources assumptions that lead to the

development of that portfolio. The Plan recognizes:

• the transfer of a 50% undivided ownership interest in the Mitchell Plant on

January 1, 2014,

• the retirement of Big Sandy Unit 2 in 2015,

• the conversion of Big Sandy Unit Ito gas in 2016, and

12

Projected Peak Demands, Capabilities and Margins

At Time of Summer Peak (UCAP)

2014-2028

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

1,259 1,278 1,304 1,159 1,160 1,161 1,162 1,167 1,172 1,174 1,175 1,182 1,186 1,192 1,195

Capability

(MW) 1,783 1,316 1,326 1,326 1,331 1,331 1,336 1,336 1,336 1,336 1,336 1,333 1,333 1,333 1,331

Reserve

(MW) 524 38 22 167 171 170 174 169 164 162 161 151 147 141 136

Margin

(%) 64.1% 18.7% 17.6% 32.3% 32.6% 32.5% 32.9% 32.3% 31.8% 31.6% 31.4% 30.4% 29.9% 29.3% 28.8%

Peak Demand

(MW)

f2t; KENTUCKY mm" POWER


® Kentucky Power also expects to purchase 58.5 MW of capacity and energy from

the ecoPower biomass facility beginning in 2017.

• AEPSC on behalf of the Company issued a Request for Information (RFI) on

October 18, 2013 for non-binding indicative responses for a 100 MW (nameplate)

power purchase agreement.

First, Table 5 compares projected summer peak demands—net of DSM—with

the projected capacity for Kentucky Power and presenting the resulting reserve margins

prior to any new capacity additions (i.e., going-in). Again, this represents the (summer)

capacity planning criterion that Kentucky Power is obligated to uphold in PJM.

Table 5: Summer Peak Going-In Reserve

In contrast, Table 6 compares projected winter peak demands—net of DSM—

with essentially the same projected capacity for Kentucky Power. This winter going-in

capacity/reserve margin position is clearly unique for the Company in that it clearly sets

forth the additional obligations around resource adequacy that must be considered by

13

KENTUCKY "°•1 POWER

A unit olAmerican Electric Power 2013 Integrated Resource Plan

Kentucky Power over-and-above the summer season obligations set forth by the PJM

RTO.

Table 6: Winter Peak Going-In Reserve

Projected Peak Demands, Capabilities and Margins

At Time of Winter Peak (UCAP)

2014-2028

Demand Capability Reserve Margin (MW) (MW) (MW) (% )

2014 1,431 2,251 820 57.3% 2015 1,432 1,433 1 0.1% 2016 1,431 1,433 2 0.1% 2017 1,431 1,438 7 0.5% 2018 1,432 1,438 6 0.4% 2019 1,430 1,444 14 1.0% 2020 1,436 1,444 8 0.6% 2021 1,439 1,444 5 0.3% 2022 1,438 1,444 6 0.4% 2023 1,438 1,444 6 0.4% 2024 1,444 1,444 0 0.0% 2025 1,448 1,441 (7) -0.5% 2026 1,452 1,441 (11) -0.8% 2027 1,454 1,441 (13) -0.9% 2028 1,459 1,438 (21) -1.4%

1.6.1 Kentucky Power Stand Alone

(807 KAR 5:058 Sec. 5.4)

On page 5 of the Commission's Order dated December 13, 2004 in Case No.

2004-00420, "In the Matter of: Application of Kentucky Power Company for Approval

of a Stipulation and Settlement Agreement Resolving State Regulatory Matters"

(commonly referred to as the Rockport Settlement Agreement), the Company was

directed that its future IRP's should reflect the resources available to Kentucky Power as

a "stand-alone" utility, as well as the resources available to it as a member of any power-

pooling arrangement that is anticipated to exist during the period reflected in the IRP.

The motivation for such a historical perspective has now been affirmed by virtue of the

14

KENTUCKY mm, POWER


upcoming elimination of the AEP Interconnection Agreement and the proposed adoption

of the PCA which would effectively establish Kentucky Power as a 'stand-alone' entity

from a planning perspective.

Therefore, the discussion and Exhibits in Chapter 4 of this report all reflect this

planning solely from the perspective of Kentucky Power as a stand-alone company.

Those Preferred Portfolio resources—as detailed in Chapter 4—ensure that, as a stand-

alone utility, Kentucky Power would have adequate capacity to achieve its PJM

minimum (capacity) reserve margin criterion through 2028 and would ensure that the

Company will be able to provide sufficient, diverse resources to achieve its customers'

energy requirements going-forward.

1.7 Significant Changes from the Previous IRP Filing

(807 KAR 5:058 Sec. 6)

Significant changes from the previously-filed 2009 IRP to this current 2013 IRP

are as follows by major function:

Load Forecast In the four years since the last IRP filing for the Company, there have been

changes to the customer base in Kentucky. For example, the residential customer counts

have decreased. The mining sector sales have been sharply reduced. Appliance and

equipment efficiency standards continue to be a driving force in conserving energy and

diminished electricity consumption. These, along with other factors, have resulted in a

lowered load forecast. See Chapter 2, Sec. I. for further details.

Resource Planning With regards to the resource planning aspect of this IRP report, the following

changes have been addressed in this report:

• Dissolution of the AEP-East Pool – see Chapter 1, Section 1.1.

• Finalization of the MATS rule and the ultimate retirement of Big Sandy unit 2

and the decision to convert Big Sandy unit 1 to a gas-fired generating unit – see

Chapter 4, Sections 4.2.3. and 4.3.2.

• Retail competition in Ohio resulting in the divestiture of Ohio Power's generating

assets, making Mitchell Units 1 and 2 available to Kentucky Power – see Chapter

4, Section 4.3.4.

15

► KENTUCKY mm, POWER


Supply-side Plan — see comparison in Exhibit 4-15. The plan now includes a mix

of specific renewable and traditional supplies.

DSM The EE landscape, in Kentucky and nationwide, is one that is increasingly

challenging. Economic conditions have not fully rebounded from the effects of the most

recent recession, depressing energy and capacity prices. In addition, increased lighting

standards have been fully phased-in, limiting the prospective savings possible with utility

lighting programs, which have provided the bulk of savings to-date. Efficiency programs

that provide the same level of energy savings for the cost and are as readily excepted by

consumers have not yet emerged. As part of the Mitchell Transfer Stipulation and

Settlement Agreement, Kentucky Power agreed to increase spending on cost-effective EE

programs to $6 million annually by 2016.

Chapter 3 discusses in greater detail the process used to determine an appropriate

level of prospective demand-side programs.

Environmental Compliance This 2013 IRP considers the impacts of final and proposed EPA regulations to

Kentucky Power generating facilities. In addition, the IRP development process assumes

there may likely be future regulation of GHG/CO2 emissions which would become

effective at some point in the 2022 timeframe. Emission compliance requirements have a

major influence on the consideration of new supply-side resources for inclusion in the

IRP because of the potential significant effects on both capital and operational costs.

Moreover, the cumulative cost of complying with these rules will ultimately have an

impact on proposed retirement dates of existing coal-fueled units that would otherwise be

forced to install emission control equipment. Details of AEP's strategy for compliance

with each EPA rule, as it becomes effective, as well as the prospect of GHG regulation

are provided in Section 4.2.4.

Fuel Procurement There have been no significant changes in the area of fuel procurement practices

since the 2009 IRP report.

16

fali KENTUCKY °m0 POWER


1.8 Financial Information (807 KAR 5:058 Sec. 9)

The average "real" rate per kWh expected to be paid by Kentucky Power

customers from 2014 to 2028 that results directly from the costs and energy consumption

impacts associated with this plan—only—is shown in Table 7. As previously stated,

Kentucky Power does not expect to add any major new baseload generation during the

2014-2028 period, however, renewable projects and new EE programs will require

modest investments and/or purchase obligations. With that, on a real (2014) dollar basis

as reflected in Table 7, this Preferred Portfolio would not be anticipated to result in an

increase in the price of power to the Company's customers.

Further, based on the load forecast to be discussed in Section 2 and a discount rate

of 8.66%, each difference in CPW between alternatives of $1,000,000,000 (one billion

dollars)—to be discussed in Chapter 4—equates to approximately 1.7 0/kWh

Table 7: Financial Effects*

Revenue Requirements Preferred Plan

Year Nominal ($/kWh)

Real ($2014/kWh)

2014 $ 0.087 $ 0.087 2015 $ 0.084 $ 0.083 2016 $ 0.092 $ 0.089 2017 $ 0.089 $ 0.084 2018 $ 0.091 $ 0.084 2019 $ 0.091 $ 0.082 2020 $ 0.093 $ 0.083 2021 $ 0.094 $ 0.082 2022 $ 0.107 $ 0.091 2023 $ 0.107 $ 0.090 2024 $ 0.109 $ 0.089 2025 $ 0.110 $ 0.088 2026 $ 0.110 $ 0.087 2027 $ 0.111 $ 0.086 2028 $ 0.112 $ 0.085

* Note: The Financial Effects represented do not consider the prospect of increases in Kentucky Power's transmission and distribution-related costs over this period, as well as increases in base generation-related costs not uniquely incorporated into the planning/modeling process.

17

► KENTUCKY •• POWER

A oil of American Electric Power 2013 Integrated Resource Plan

1.9 Next Steps, Key Issues/Uncertainties

1.9.1 Implementation Steps

(807 KAR 5:058 Sec. 5.5)

Steps to be taken during the next three (3) years to implement the plan are as follows:

Wind Projects

Pursuant to the Mitchell Transfer Stipulation and Settlement Agreement approved

by the Commission, Kentucky Power issuesd a Request for Information (RFI) on

potential terms for a 100 MW wind PPA beginning in 2017. The Company received

twenty-five non-binding proposals. The Company has not rendered any decision

regarding any ultimate disposition plan pertaining to wind resources. Rather, a discussion

of the wind proposals and Kentucky Power's preferred course of action are offered in

Section 4.6.4.

Stipulated Energy Efficiency Spending

To realize the resource planning benefits associated with the incremental EE

resources set forth in the IRP process, Kentucky Power will need to obtain customer

acceptance and participation in the new and expanded DSM programs. In the near term,

an expansion of current programs is the most practical way to adhere to the stipulated

settlement agreement. Subsequently, new programs that, to the extent practicable, target

customer segments and end uses identified in the analyses in Chapter 3 must be

developed and introduced.

Load Forecasting

With regard to load forecasting, the Company will continue to evaluate and

incorporate the effects of the economy and the EE programs including federal mandates

and expanded EE programs.

1.9.2 Key Issues/Uncertainties

(807 KAR 5:058 Sec. 5.6)

Key issues or uncertainties that could affect successful implementation of the plan are as follows:

18

KENTUCKY POWER'



Resource Planning

The plan represented in this report meets the objectives mentioned above, having

planning flexibility and adaptability to risk. Kentucky Power's supply-side plan does not

entail much risk or uncertainty. Perhaps the uncertainty presenting the largest challenge

is the potential impact of greenhouse gas rules for existing coal units. The Company

believes that the impact of such rules, if any, will not be material until the early 2020's.

DSM

In the area of DSM, the key issues and/or uncertainties are: 1) the degree of

customer acceptance of offered DSM programs in that achieving the high levels of EE

will require customers to embrace these efforts in unprecedented numbers; 2) the impact

on ratepayers and their ability to fund DSM programs, since ramping up customer

participation to achieve planning levels will require up-front investment by ratepayers

(i.e., they will see increased bills); and 3) whether or not in today's economic climate,

regulators will approve the increased spending that accompanies increasing levels of

implementation of utility-sponsored DSM programs due to its impact upon customers'

bills.

Load Forecasting

A major uncertainty is how strong will the economy be in the future. The

economy has a direct impact on the Company's load. The Company provides a broad

overview of a high and low economic forecast scenario. See Section 2.2 for more details.

Transmission

As a result of the AEP - East Zone transmission system's geographical location

and expanse, as well as its numerous interconnections, the AEP-East Zone transmission

system can be influenced by both internal and external factors. Facility outages, load

changes, or generation redispatch on neighboring companies' systems, in combination

with power transactions across the interconnected network, can affect power flows on

AEP's eastern transmission facilities. As a result, the eastern transmission system is

designed and operated to perform adequately even with the outage of its most critical

transmission elements or the unavailability of generation. The AEP - East Zone

19

KENTUCKY l'im• POWER


transmission system conforms to the NERC Reliability Standards and the applicable

ReliabilityFirst Corporation standards and performance criteria.

The AEP - East Zone transmission system assets are aging and some station

equipment is becoming obsolete. Therefore, in order to maintain acceptable levels of

reliability, significant investments will have to be made over the next ten years to

proactively replace the most critical aging and obsolete equipment and transmission lines.

Environmental Compliance

Currently the Clean Air Interstate Rule (CAIR), which became effective in July

2005 and called for significant reductions of NOx and SO2, beginning in 2009 and 2010,

respectively, has been remanded by the D.C. Circuit Court to the EPA for further

rulemaking in response to the legal appeals of this rule. While EPA addresses the

deficiencies identified by the Court, the compliance requirements of CAIR remain in

effect. There is a great deal of uncertainty over what approach EPA will take to rewrite

the CAIR and its associated compliance requirements. For purposes of planning, the AEP

System expects the CAIR program to be replaced with a more restrictive policy.

As a replacement to the vacated Clean Air Mercury Rule (CAMR), EPA set forth

the Mercury and Air Toxics Standards (MATS) Rule which became effective on April

16, 2012. The goal of the MATS Rule is to reduce hazardous air pollutants (HAPs) from

coal- and oil-fired electric generating units. The final rule includes stringent emission

limits for mercury, particulate matter (PM) (as a surrogate for non-mercury metals), as

well as acid gases, with either hydrochloric acid (HCI) or SO2 serving as surrogates for

acid gases. The initial compliance date for the MATS Rule is April 16, 2015. The MATS

Rule will likely have a significant impact on proposed retirement dates of older, non-

controlled units and ultimately the timing for new capacity.

Finally, EPA continues to move forward in implementing a regulatory approach

for controlling GHG emissions from power plants. In 2010, EPA promulgated the GHG

Tailoring Rule that establishes thresholds for regulating GHG emissions from new power

plants or from existing units that undergo major modifications. Also, on April 13, 2012,

EPA proposed New Source Performance Standards (NSPS) for new fossil fuel power

20

r KENTUCKY POWER


plants with a CO? emission limit of 1,000 lb/MWh, which is equivalent to the rate EPA

assumes for a new natural gas combined cycle (CC) unit. EPA did not issue a final rule

based on this proposal as expected. Under President Obama's direction, the EPA issued a

revised proposal for the GHG NSPS for new sources on September 20, 2013, and must

finalize them in a "timely fashion." This second proposal included a CO2 emission limit

of 1,100 lb./MWh for new fossil fuel power plants.

For existing sources, the EPA was directed to propose guidelines by June 1, 2014,

and finalize those standards by June 1, 2015. States would develop and submit a plan to

EPA for implementing the existing source standards by June 30, 2016. The scope and

timing of these requirements have not yet been determined. Such GHG rules could

impose greater operating costs on Kentucky Power Company's power plants in future

years.

Coal Market Uncertainties

Coal market price volatility has increased due to various events affecting the

supply and demand posture of coal in the international markets. Various countries have

lessened their previously stated export coal quantities to rebuild domestic stockpiles,

which caused all international coal markets to tighten and prices to rise significantly.

Additionally, the decreased value of the U.S. dollar relative to most major foreign

currencies contributed to U.S. coal being more competitive based on price in the

international export market. There also has been an increasingly strong demand for coal

world wide, especially in emerging economies, along with sustained coal consumption in

the United States. Early last year the global demand for coal seemed insatiable and that

demand placed a significant upward pressure on the price of coal. Conversely, since last

fall, there was a slow down in the world and U.S. economies, that reduced demand for

U.S. coal and has effectively lowered the market price.

21

KENTUCKY '•°' POWER


1.10 Cross Reference Table

(807KAR5:058 SECTION 4)

Kentucky Power has included a Cross Reference Table below that lists the section

and sub-section numbers found in Administrative Regulation 807KAR5:058 "Integrated

Resource Planning by Electric Utilities" along with the corresponding report Sections

and/or Exhibits of Kentucky Power's IRP Plan. This Cross Reference Table is provided

in order to satisfy Section 4 of the IRP regulation.

...........

22

KENTUCKY POWER '


Cross Reference Table IRP Regulation (807 KAR 5:058)

Report Reference

May 31, 2013 Letter: Pursuant to the Commission's Order of March 29, 2004, in Administrative Case No. 387 ("Admin 387"), each jurisdictional electric generating utility is required to file annual resource Information with the CorrMssion. Certain informetion relates to the demand and energy forecasts and reserve margins.

Given the actual and projected price Increases resulting from new environmental requirements which the generating utilities are being required to address, recent Staff Reports analyzing the generation utilities' integrated resource plans have included recommendations regarding price elasticity issues. For example, the recent Staff Report issued In Case No. 2012-00140 Included the following recommendation: "Staff recommends that LG&E/KU discuss the impact on demand of recent and projected increases In the price of electricity to their customers In the next IRP. The price elasticity of the demand for electricity should be fully examined and a sensitivity analysis performed."

Due to the increasing impact that price elasticity will have on electric utility sales and revenues, the Staff and Commission ask that you provide a detailed discussion of the consideration given to price elasticity In the forecasted demand, energy and reserve margin information provided with the annual Admin 387 resource assessments. For the Admin 387 forecasted information filed earlier in 2013, we ask that you provide the discussion of price elasticity no later than June 30, 2013. For succeeding years, the price elasticity discussion should be provided as a supplement to the information required by the Admin 387 Order. Section 2.7

Kentucky IRP Standard: Case No. 2008-00408 Order dated July 24, 2012 (Ordering paragraph 9 amended August 6, 2012, none pro tune)

Each electric utility shall integrate energy efficiency resources into its plans and shall adopt policies establishing cost-effective energy efficiency resources with equal priority as other resource options.

In each integrated resource plan, certificate case, and rate case, the subject electric utility shall fully explain its consideration of cost-effective energy efficiency resources as defined in the Commission's IRP regulation (807 KAR 5:05 El ) . Chanter 3, Sections 3.5.5 and 3.5.6 807 KAR 5:058. Integrated resource planning by electric utilities

Section 1. General Provisions

(1) This administrative regulation shall apply to electric utilities under commission jurisdiction except a distribution company with less than $10,000,000 annual revenue or a distribution cooperative organized under KRS Chapter 279. (2) Each electric utility shall file triennially with the commission an integrated resource plan. The plan shall include historical and projected demand, resource, and financial data, and other operating performance and system information, and shall discuss the facts, assumptions, and conclusions, upon which the plan Is based and the actions it proposes. (3) Each electric utility shall file ten (10) bound copies and one (1) unbound, reproducible copy of its Integrated resource plan with the commission. Section 2. Filing Schedule. (1) Each electric utility shall file Its Integrated resource plan according to a staggered schedule which provides for the filing of integrated resource plans one (1) every six (6) months beginning nine (9) months from the effective date of this administrative regulation. (a) The integrated resource plans shall be flied at the specified times following the effective date of this administrative regulation: 1. Kentucky Utilities Company shall file nine (9) months from the effective date;

2. Kentucky Power Company shall file fifteen (15) months from the effective date;

In curnolence with the KPSCM, Order in Cure No. 2012-

00344 dated 7-30-12, the Company yalfde before 12-31-13.

3. East Kentucky Power Cooperative, Inc. shall file twenty-one (21) months from the effective date• 4. The Union Light, Heat & Power Company shall file twenty-seven (27) months from the effective date; 5. 131g Rivers Electric Corporation shall file thirty-three (33) months from the effective date; and 6. Louisville Gas & Electric Company shall file thirty-nine (39) months from the effective date. (b) The schedule shall provide at such time as all electric utilities have filed integrated resource plans, the sequence shall repeat. (c) The schedule shall remain In effect until changed by the commission on Its own motion or on motion of one (1) or mom electric utilities for good cause shown. Good cause may include a change In a utility's financial or resource conditions. (d) If any filing date falls on a weekend or holiday, the plan shall be submitted on the first business day following the scheduled filing date.

23

F , KENTUCKY POWER


Cross Reference Table IRP Regulation (807 KAR 5:058

Report Reference

(2) Immediately upon filing of an integrated resource plan, each utility shall provide notice to intervenors in its last integrated resource plan review proceeding, that its plan has been filed and is available from the utility upon request. The Company will comply with this requirement. (3) Upon receipt of a utility's integrated resource plan, the commission shall establish a review schedule which may include interrogatories, comments, informal conferences, and staff reports. Section 3. Waiver. A utility may file a motion requesting a waiver of specific provisions of this administrative regulation. Any request shall be made no later than ninety (90) days prior to the date established for filing the integrated resource plan. The commission shall rule on the request within thirty (30) days. The motion shall clearly identify the provision from which the utility seeks a waiver and provide justification for the requested relief which shall include an estimate of costs and benefits of compliance with the specific provision. Notice shall be given in the manner provided in Section 2(2) of this administrative regulation. No Waivers have been requested. Section 4. Format (1) The integrated resource plan shall be clearly and concisely organized so that it is evident to the commission that the utility has complied with reporting requirements described in subsequent sections. Chapter 1.0 - Cross-reference Table

(2) Each plan filed shall identify the individuals responsible for its preparation, who shall be available to respond to inquiries during the commission's review of the plan.

Direct Inquiries to Ranie K Wohnhas, KPCo's Managing Director of Regulatory and Finance. The lead preparers for Chapters 2, 3, and 4 are Randy Holliday (Economic Forecasting), William Castle (Resource Planning - DSM) and John Torpey (Resource Planning -Supplv/Integration), respectively.

Section 5. Plan Summary The plan shall contain a summary which discusses the utility's projected load growth and the resources planned to meet that growth. The summary shall include at a minimum: Chapter 1.0 (1) Description of the utility, its customers, service territory, current facilities, and planning objectives; Chapter 1.2 and Chapter 1.3

(2) Description of models, methods, data, and key assumptions used to develop the results contained in the plan; Chapter 1.4 , Chapter 2 Sections 2.1, 2.2, 2.3 and 2.4. (3) Summary of forecasts of energy and peak demand, and key economic and demographic assumptions or projections underlying these forecasts; Chapter 1.4 (4) Summary of the utility's planned resource acquisitions including improvements in operating efficiency of existing facilities, demand-side programs, nonutility sources of generation, new power plants, transmission improvements, bulk power purchases and sales, and interconnections with other utilities;

Chapter 1, Sections 1.4, 1.5, 1.6 Chapter 4.4.1 and Exhibit 4-18

(5) Steps to be taken during the next three (3) years to implement the plan; Chapter 1.9.1 (6) Discussion of key issues or uncertainties that could affect successful implementation of the plan. Chapter 1.9.2 Section 6. Significant Changes All integrated resource plans, shall have a summary of significant changes since the plan most recently filed. This summary shall describe, in narrative and tabular form, changes in load forecasts, resource plans, assumptions, or methodologies from the previous plan. Where appropriate, the utility may also use graphic displays to illustrate changes.

Chapter 1.7 and Chapter 2.9 and Chapter 3.1.1 and Exhibit 4-15

Section 7. Load Forecasts The plan shall include historical and forecasted information regarding loads. Chapter 2.5.1 and Chapter 2.5.2 (1) The information shall be provided for the total system and, where available, disaggregated by the following customer classes: Chapter 2.5 note Residential forecast in aggregate (a) Residential heating; Chapter 2.10 (b) Residential nonheating; Chapter 2.10 (c) Total residential (total of paragraphs (a) and (b) of this subsection); Chapter 2.5 (d) Commercial; Chapter 2.5 (e) Industrial; Chapter 2.5 (f) Sales for resale; Chapter 2.5 (g) Utility use and other. Chapter 2.5 The utility shall also provide data at any greater level of disaggregation available. Chapter 2.5

24

_ _E N U C K Y _ AVER A unit of American Electric Power



Report Reference

(2) The utility shall provide the following historical information for the base year, which shall be the most recent calendar year for which actual energy sales and system peak demand data are available, and the four (4) years preceding the base year: Chapter 2.10 (a) Average annual number of customers by class as defined in subsection (1) of this section; Chapter 2.10 (b) Recorded and weather-normalized annual energy sales and generation for the system, and sales disaggregated by class as defined in subsection (1) of this section; Chapter 2.10 (c) Recorded and weather-normalized coincident peak demand in summer and winter for the system; Chapter 2.10 (d) Total energy sales and coincident peak demand to retail and wholesale customers for which the utility has firm, contractual commitments; Chapter 2.10 (e) Total energy sales and coincident peak demand to retail and wholesale customers for which service is provided under an interruptible or curtailable contract or tariff or under some other nonfirm basis; Chapter 2.10 (f) Annual energy losses for the system; Chapter 2.10 (g) Identification and description of existing demand-side programs and an estimate of their impact on utility sales and coincident peak demands including utility or government sponsored conservation and load management programs; Chapter 2.5.2; Chapter 3.1.2; Chapter 3.8 (h) Any other data or exhibits, such as load duration curves or average energy usage per customer, which illustrate historical changes in load or load characteristics. Chapter 2.10

(3) For each of the fifteen (15) years succeeding the base year, the utility shall provide a base load forecast it considers most likely to occur and, to the extent available, alternate forecasts representing lower and upper ranges of expected future growth of the load on its system. Forecasts shall not include load impacts of additional, future demand-side programs or customer generation included as part of planned resource acquisitions estimated separately and reported in Section 8(4) of this administrative regulation. Forecasts shall include the utility's estimates of existing and continuing demand-side programs as described in subsection (5) of this section. Chapter 2.5 (4) The following information shall be filed for each forecast: (a) Annual energy sales and generation for the system and sales disaggregated by class as defined in subsection (1) of this section; Chapter 2.5 (b) Summer and winter coincident peak demand for the system; Chapter 2.5 (c) If available for the first two (2) years of the forecast, monthly forecasts of energy sales and generation for the system and disaggregated by class as defined in subsection (1) of this section and system peak demand; Chapter 2.5 (d) The impact of existing and continuing demand-side programs on both energy sales and system peak demands, including utility and government sponsored conservation and load management programs Chapter 2.5, Chapter 2.6. (e) Any other data or exhibits which illustrate projected changes in load or load characteristics. Chapter 2.3.3.2 and 2.3.3.3 (5) The additional following data shall be provided for the integrated system, when the utility is part of a multistate integrated utility system, and for the selling company, when the utility purchases fifty (50) percent of its energy from another company: (a) For the base year and the four (4) years preceding the base year

1. Recorded and weather normalized annual energy sales and generation; Chapter 2.10 2. Recorded and weather-normalized coincident peak demand in summer and winter. Chapter 2.10 (b) For each of the fifteen (15) years succeeding the base year:

1. Forecasted annual energy sales and generation; Chapter 2.5 2. Forecasted summer and winter coincident peak demand. Chapter 2.5 (6) A utility shall file all updates of load forecasts with the commission when they are adopted by the utility. Chapter 2.12.3 (7) The plan shall include a complete description and discussion of: (a) All data sets used in producing the forecasts; Chapter 2 Appendix Vol. B (b) Key assumptions and judgments used in producing forecasts and determining their reasonableness; Chapter 2.3 and 2.4 and Chapter 2 Appendix Vol. B

25




Report Reference

(c) The general methodological approach taken to load forecasting (for example, econometric, or structural) and the model design, model specification, and estimation of key model parameters (for example, price elasticities of demand or average energy usage per type of appliance); Chapter 2.2, 2.3 and 2.4 (d) The utility's treatment and assessment of load forecast uncertainty; Chapter 2.8 (e) The extent to which the utility's load forecasting methods and models explicitly address and incorporate the following factors: Chapter 13 and Chapter 2 Appendix Vol. e 1. Changes in prices of electricity and prices of competing fuels; Chapter 2.3, 2.7 and Chapter 2 Appendix Vol. B 2. Changes In population and economic conditions In the utility's service territory and general region; Chapter 2.3 and Chapter 2 Appendix Vol. B 3. Development and potential market penetration of new appliances, equipment, and technologies that use electricity or competing fuels; and Chapter 2.3 and Chapter 2 Appendix Vol. B 4. Continuation of existing company and government sponsored conservation and load management or other demand-side programs. Chapter 2.3 and Chapter 2 Appendix Vol. B (f) Research and development efforts underway or planned to improve performance, efficiency, or capabilities of the utility's load forecasting methods; and Chapter 2.9.3 (g) Description of and schedule for efforts underway or planned to develop end-use load and market data for analyzing demand-side resource options Including load research and market research studies, customer appliance saturation studies, and conservation and load management program pilot or demonstration projects. Chapter 2.10

Technical discussions, descriptions, and supporting documentation shall be contained in a technical appendix. Chapter 2 Appendix Vol. B Section 8. Resource Assessment and Acquisition Plan ,,,,,,

(1) The plan shall include the utility's resource assessment and acquisition plan for providing an adequate and reliable supply of electricity to meet forecasted electricity requirements at the lowest possible cost. The plan shall consider the potential impacts of selected, key uncertainties and shall include assessment of potentially cost-effective resource options available to the utility. Chanter 4.0

(2) The utility shall describe and discuss all options considered for inclusion in the plan Including: (a) Improvements to and more efficient utilization of existing utility generation, transmission, and distribution facilities; Chapter 4.3.2.2

(b) Conservation and load management or other demand-side programs not already in place; Chapter 3.4 and Chapter 3.5

(c) Expansion of generating facilities, including assessment of economic opportunities for coordination with other utilities in constructing and operating new units; and Chapter 4

(d) Assessment of nonutility generation, including generating capacity provided by cogeneration, technologies relying on renewable resources, and other nonutility sources. Chapter 4.3.4 and Chapter 4.3.2.3

(3) The following information regarding the utility's existing and planned resources shall be provided. A utility which operates as part of a multistate integrated system shall submit the following information for its operations within Kentucky and for the multistate utility system of which it is a part. A utility which purchases fifty (50) percent or more of its energy needs from another company shall submit the following information for Its operations within Kentucky and for the company from which it purchases its energy needs.

(a) A map of existing and planned generating facilities, transmission facilities with a voltage rating of sixty-nine (69) kilovolts or greater, indicating their type and capacity, and locations and capacities of all interconnections with other utilities. The utility shall discuss any known, significant conditions which restrict transfer capabilities with other utilities.

Confidential Exhibits 4-16 & Confidential Exhibit 4-17 vol. D

(b) A list of all existing and planned electric generating facilities which the utility plans to have in service in the base year or during any of the fifteen (15) years of the forecast period including for each facility: 1. Plant name; Exhibit 4-2 and Exhibits 4-12 and 4-13 2. Unit number(s); Exhibit 4-2 and Exhibits 4-12 and 4-13 3. Existing or proposed location; Exhibit 4-2 and Exhibits 4-12 and 4-13 4. Status (existing, planned, under construction, etc.)* Exhibit 4-2 and Exhibits 4-12 and 4-13 5. Actual or projected commercial operation date; Exhibit 4-2 and Exhibits 4-12 and 4-13 6. Type of facility; Exhibit 4-2 and Exhibits 4-12 and 4-13 7. Net dependable capability, summer and winter, Exhibit 4-2 and Exhibits 4-12 and 4-13 8. Entitlement if jointly owned or unit purchase* Exhibit 4-2 and Exhibits 4-12 and 4-13

26

KEN1 KY POW{ A unit of American Electric Power



Report Referen

9. Primary and secondary fuel types, by unit; Exhibit 4-2 and Exhibits 4-10 through 4-13 10. Fuel storage capacity; Exhibit 4-2 and Exhibits 4-10 through 4-13 11. Scheduled upgrades, deratings, and retirement dates; Exhibits 4-10 through 4-13

12. Actual and projected cost and operating information for the base year (for existing units) or first full year of operations (for new units) and the basis for projecting the information to each of the fifteen (15) forecast years (for example, cost escalation rates). All cost data shall be expressed in nominal and real base year dollars. a. Capacity and availability factors; Exhibits 4-5 and Confidential 4-6 Vol. D b. Anticipated annual average heat rate; Exhibits 4-5 and Confidential 4-6 Vol. D c. Costs of fuel(s) per millions of British thermal units (MMBtu); Exhibit 4-3 and Confidential Exhibit 4-4 Vol. D

d. Estimate of capital costs for planned units (total and per kilowatt of rated capacity); Chapter 4.C.2.a. and Confidential Exhibit 4-9 Vol. D e. Variable and fixed operating and maintenance costs; Exhibit 4-3 and Confidential Exhibit 4-4 Vol. D f. Capital and operating and maintenance cost escalation factors; Chapter 4.3.5.2

g. Projected average variable and total electricity production costs (in cents per kilowatt-hour). Confidential Exhibit 4-4 Vol. D

(c) Description of purchases, sales, or exchanges of electricity during the base year or which the utility expects to enter during any of the fifteen (15) forecast years of the plan. Exhibits 4-10 through 4-13

(d) Description of existing and projected amounts of electric energy and generating capacity from cogeneration, self-generation, technologies relying on renewable resources, and other nonutility sources available for purchase by the utility during the base year or during any of the fifteen (15) forecast years of the plan. Chapter 4.3.4.1 and Chapter 4.3.2.1 (e) For each existing and new conservation and load management or other demand-side programs included in the plan: 1. Targeted classes and end-uses; Chapter 3.8; Chapter 3.5.5. and Exhibit 3-3 2. Expected duration of the program; Chapter 3.5.7

3. Projected energy changes by season, and summer and winter peak demand changes; Chapter 3.5.6, Exhibit 3-4, and Chapter 3.8, Filed DSM Programs see Chapters 2.6 and Chapter 2.5.2

4. Projected cost, including any incentive payments and program administrative costs; and Chapter 3.8; Chapter 3.5.7 and Exhibit 3-5

5. Projected cost savings, including savings In utility's generation, transmission and distribution costs. Chapter 3.5.7, Chapter 3.8

(4) The utility shall describe and discuss its resource assessment and acquisition plan which shall consist of resource options which produce adequate and reliable means to meet annual and seasonal peak demands and total energy requirements identified in the base load forecast at the lowest possible cost. The utility shall provide the following information for the base year and for each year covered by the forecast: (a) On total resource capacity available at the winter and smmer peak: 1. Forecast peak load; Exhibits 4-10 through 4-13 2. Capacity from existing resources before consideration of retirements; Exhibits 4-10 through 4-13 3. Capacity from planned utility-owned generating plant capacity additions; Exhibits 4-10 through 4-13 4. Capacity available from firm purchases from other utilities; Exhibits 4-10 through 4-13 5. Capacity available from firm purchases from nonutility sources of generation; Exhibits 4-10 through 4-13 6. Reductions or Increases in peak demand from new conservation and load management or other demand-side programs;

Exhibits 4-10 through 4-13, filed DSM Program Chapter 2.6 and Chapter 2.5.2 Also Exihibt 3-4

7. Committed capacity sales to wholesale customers coincident with peak; Exhibits 4-10 through 4-13 8. Planned retirements; Exhibits 4-10 through 4-13 9. Reserve requirements; Exhibits 4-10 through 4-13 10. Capacity excess or deficit; Exhibits 4-10 through 4-13 11. Capacity or reserve margin. Exhibits 4-10 through 4-13 (b) On planned annual generation: 1. Total forecast firm energy requirements; Exhibit 4-14

2. Energy from existing and planned utility generating resources disaggregated by primary fuel type; Exhibit 4-14 3. Energy from firm purchases from other utilities; Exhibit 4-14 4. Energy from firm purchases from nonutility sources of generation; and Exhibit 4-14

27




Report Reference

5. Reductions or increases in energy from new conservation and load management or other demand-side programs; Exhibit 3-4 and Exhibit 4-14

(c) For each of the fifteen (15) years covered by the plan, the utility shall provide estimates of total energy input in primary fuels by fuel type and total generation by primary fuel type required to meet load. Primary fuels shall be organized by standard categories (coal, gas, etc.) and quantified on the basis of physical units (for example, barrels or tons) as well as in MMBtu. Exhibit 4-14

(5) The resource assessment and acquisition plan shall include a description and discussion of

(a) General methodological approach, models, data sets, and information used by the company; Chapters 4.1, 4.3 and 4.5 (b) Key assumption and judgments used in the assessment and how uncertainties in those assumptions and judgments were incorporated into analyses; Chapter 1.9

(c) Criteria (for example, present value of revenue requirements, capital requirements, environmental impacts, flexibility, diversity) used to screen each resource alternative including demand-side programs, and criteria used to select the final mix of resources presented in the acquisition plan; Chapters 4.1 and 4.5

(d) Criteria used in determining the appropriate level of reliability and the required reserve or capacity margin, and discussion of how these determinations have influenced selection of options; Chapter 4.2.2 (e) Existing and projected research efforts and programs which are directed at developing data for future assessments and refinements of analyses; Chapter 4.3.4

(f) Actions to be undertaken during the fifteen (15) years covered by the plan to meet the requirements of the Clean Air Act amendments of 1990, and how these actions affect the utility's resource assessment; and Chapter 4.2.4

(g) Consideration given by the utility to market forces and competition in the development of the plan. Chapter 4.3.4.1

Technical discussion, descriptions and supporting documentation shall be contained in a technical appendix. Chapter 4.9 Section 9. Financial Information

The integrated resource plan shall, at a minimum, include and discuss the following financial information: (1) Present (base year) value of revenue requirements stated in dollar terms; Chapter 1.8 Financial Information, Table 7 (2) Discount rate used in present value calculations; Chapter 1.8 Financial Information, Table 7 (3) Nominal and real revenue requirements by year; and Chapter 1.8 Financial Information, Table 7 (4) Average system rates (revenues per kilowatt hour) by year. Chapter 1.8 Financial Information, Table 7 Section 10. Notice

Each utility which files an integrated resource plan shall publish, In a form prescribed by the commission, notice of its filing in a newspaper of general circulation in the utility's service area. The notice shall be published not more than thirty (30) days after the filing date of the report.

The Company intends to publish Notices on or before January 20, 2014.

Section 11 Procedures for Review of the Integrated Resource Plan

(1) Upon receipt of a utility's integrated resource plan, the commission shall develop a procedural schedule which allows for submission of written interrogatories to the utility by staff and intervenors, written comments by staff and intervenors, and responses to interrogatories and comments by the utility. (2) The commission may convene conferences to discuss the filed plan and all other matters relative to review of the plan. (3) Based upon its review of a utility's plan and all related information, the commission staff shall issue a report summarizing its review and offering suggestions and recommendations to the utility for subsequent filings.

(4) A utility shall respond to the staffs comments and recommendations in its next integrated resource plan filing. The Company intends to comply with this requirement.

28

KENTUCKY ER


2.0 LOAD FORECAST

29

Lai KENTUCKY imm POWER

A unit o/ American Electric Power 2013 Integrated Resource Plan

2.1 Summary of Load Forecast

2.1.1 Forecast Assumptions

(807 KAR 5:058 Sec. 5.2.)

The load forecasts for Kentucky Power and the other operating companies in the

AEP System are based on a forecast of U.S. economic growth provided by Moody's

Analytics. The load forecasts presented herein are based on a Moody's Analytics

economic forecast issued in December 2012 and on Kentucky Power load experience

prior to 2013. Moody's Analytics projects moderate growth in the U.S. economy during

the 2014-2028 forecast period, characterized by a 2.4% annual rise in real Gross

Domestic Product (GDP), and moderate inflation as well, with the implicit GDP price

deflator expected to rise by 1.9% per year. Industrial output, as measured by the Federal

Reserve Board's (FRB's) index of industrial production, is expected to grow at 0.6% per

year during the same period. For the regional economic outlook, the December 2012

forecast developed by Moody's Analytics was utilized. The outlook for Kentucky

Power's service area projects employment growth of 0.2% per year during the forecast

period and real regional income per-capita growth of 2.3%.

Inherent in the load forecasts are the impacts of past customer energy

conservation and load management activities, including company-sponsored EE

programs already implemented. The load impacts of future, or expanded, EE programs

are analyzed and projected separately, and appropriate adjustments applied to the load

forecasts.

2.1.2 Forecast Highlights

Kentucky Power's total internal energy requirements, including the effects of

approved EE programs, are forecasted to increase at an average annual rate of 0.1% from

2014 to 2028. The corresponding summer and winter peak internal demands are

forecasted to grow at an average annual rate of 0.3% and 0.1%, respectively. Kentucky

Power's annual peak demand is expected to continue to occur in the winter season.

30

al; KENTUCKY POWER


The load effects of the continuation of approved energy efficiency (EE) programs

generally increase in time through about the year 2021 and then remain relatively stable.

Over the 15-year forecast period, the projected approved EE has minimal effect on load

growth. The expected annual rate of growth in internal energy requirements, as well as in

the summer and winter peak internal demands, after accounting for approved EE, is

relatively unchanged from the growth rate without approved EE. The effects of EE and

other DSM programs beyond those that have been filed will be discussed in Chapter 3.

2.2 Overview of Forecast Methodology

(807 KAR 5:058 Sec. 5.2. and Sec. 7.7.c.)

Kentucky Power's load forecasts are based mostly on econometric, supplemented

with state-of-the-art statistically adjusted end-use, analyses of time-series data -

producing an internally consistent forecast. This consistency is enhanced by model logic

expressed in mathematical terms and quantifiable forecast assumptions. This is helpful

when analyzing future scenarios and developing confidence bands. Additionally,

econometric analysis lends itself to objective model verification by using standard

statistical criteria. This is particularly helpful because it allows apples-to-apples

comparisons of different companies and forecast periods.

In practice, econometric analysis highlights alternatives in forecasting models that

may not be immediately obvious to the layperson. Likewise, professional judgment is

required to interpret statistical criteria that are not always clear-cut. Kentucky Power's

analysts strive to interpret this data to produce as useful and as accurate a forecast as

possible.

In pursuit of that goal, Kentucky Power's energy requirements forecast is derived

from two sets of econometric models: I) a set of monthly short-term models and 2) a set

of long-term models, with some using monthly data and others using annual data. This

procedure permits easier adaptation of the forecast to the various short- and long-term

planning purposes that it serves.

31

f; KENTUCKY V POWER


For the first full year of the forecast, the forecast values are governed exclusively

by the short-term models, using billed or metered energy sales. The long-term sales are

billed.

The short- and long-term forecasts are blended during the second six months of

the second year of the forecast. The blending ensures a smooth transition from the short-

term to the long-term forecast.

The blended sales forecasts are converted to billed and accrued energy sales,

which are consistent with the energy generated.

In both sets of models, the major energy classes are analyzed separately. Inputs

such as regional and national economic conditions and demographics, energy prices,

weather factors, special information such as known plans of specific major customers,

and informed judgment are all used in producing the forecasts. The major difference

between the two is that the short-term models use mostly trend, seasonal, and weather

variables, while the long-term models use structural variables, such as population,

income, employment, energy prices, and weather factors, as well as trends. Supporting

forecasting models are used to predict some inputs to the long-term energy models. For

example, natural gas models are used to predict sectoral natural gas prices that then serve

as inputs.

Either directly, through national economic inputs to the forecast models, or

indirectly, through inputs from supporting models, Kentucky Power's load forecasts are

influenced greatly by the outlook for the national economy. For the load forecasts

reported herein, Moody's Analytic's December 2012 forecast was used as the basis for

that outlook. Moody's Analytics's regional forecast, which is consistent with its national

economic forecast, was used for the regional economic forecast of income, employment,

households, output, and population

The demand forecast model is a series of algorithms for allocating the monthly

net internal energy to hourly demand. The inputs into forecasting hourly demand are

internal energy, weather, 24-hour load profiles and calendar information.

32

KENTUCKY ER


Flow charts depicting the structure of the models used in projecting Kentucky

Power's electric load requirements are shown in Exhibits 2-1. Exhibit 2-1(a) depicts the

stages in the development of the Company's short-term and long-term internal energy

requirements forecasts, along with schematic of the sequential steps for the peak demand

and internal energy requirements forecasting. Exhibit 2-1(b) identifies in greater detail

the variables included in the short-term and long-term energy requirements forecasting

models. Displays of model equations, including the results of various statistical tests,

along with data sets, are provided in the Appendix. Customer sensitive information will

be provided as Chapter 2-Confidential Appendix, Customer Sensitive Information, and is

provided in the Confidential Supplement.

2.3 Forecast Methodology for Internal Energy Requirements

(807 KAR 5:058 Sec. 5.2.and Sec. 7.7.b, c. and e.)

2.3.1 General

This section provides a detailed description of the short-term and long-term

models employed in producing the forecasts of Kentucky Power's energy consumption,

by customer class. For the purposes of the load forecast, the short term is defined as the

first two years, and the long term as the third forecast year and beyond.

Conceptually, the difference between short- and long-term energy consumption

relates to changes in the stock of electricity-using equipment, rather than the passage of

time. The short term covers the period during which changes are minimal, and the long

term covers the period during which changes can be significant. In the short term, electric

energy consumption is considered to be a function of an essentially fixed stock of

equipment. For residential and commercial customers, the most significant factor

influencing the short term is weather. For industrial customers, economic forces that

determine inventory levels and factory orders also influence short-term utilization rates.

The short-term models recognize these relationships and use weather and recent load

growth trends as the primary variables in forecasting monthly energy sales.

Over time, demographic and economic factors such as population, employment,

income, and technology determine the nature of the stock of electricity-using equipment,

33

' KENTUCKY POWER



both in size and composition. Long-term forecasting models recognize the importance of

these variables and include most of them in the formulation of long-term energy

forecasts.

Relative energy prices also have an impact on electricity consumption. One

difference between the short-term and long-term forecasting models is energy prices,

which are only included in long-term forecasts. In the short-term, conusmers have little

opportunity to respond to changes in price. In the long term, however, constraints are

lessened as durable equipment is replaced and as price expectations come to fully reflect

price changes.

2.3.2 Short-term Forecasting Models

The goal of Kentucky Power's short-term forecasting models is to produce an

accurate load forecast for the first full year into the future. To that end, the short term

forecasting models generally employ a combination of monthly and seasonal binaries,

time trends, and monthly heating/cooling degree-days in their formulation. The heating

and cooling degree-days are measured at weather stations in the Company's service area.

The forecasts relied on autoregressive integrated moving average (ARIMA) models.

The estimation period for the short-term models was January 2003 through

January 2013.

2.3.2.1 Residential and Commercial Energy Sales

Residential and commercial energy sales are developed using ARIMA models to

forecast usage per customer and number of customers. The usage models relate usage to

lagged usage, lagged error terms, heating and cooling degree-days and binary variables.

The customer models relate customers to lagged customers, lagged error terms and binary

variables. The energy sales forecasts are a product of the usage and customer forecasts.

2.3.2.2 Industrial Energy Sales

Short-term industrial energy sales are forecast separately for 10 large industrial

customers in Kentucky and for the remainder of industrial energy customers segregated

into manufacturing and mining load. These 12 short-term industrial energy sales models

relate energy sales to lagged energy sales, lagged error terms and binary variables. The

34

fKENTUCKY POWER A unit o/ American Electric Power 2013 Integrated Resource Plan

industrial models are estimated using ARIMA models. The short-term industrial energy

sales forecast is a sum of the forecasts for the 10 large industrial customers and the

forecasts for the remainder of the manufacturing and mining customers.

2.3.2.3 All Other Energy Sales

The All Other Energy Sales category for Kentucky Power includes public street

and highway lighting (or other retail sales) and sales to municipals. Kentucky Power's

municipal customers include the cities of Vanceburg and Olive Hill.

Both the other retail and municipal models are estimated using ARIMA models.

Kentucky Power's short-term forecasting model for public street and highway lighting

energy sales includes binaries, and lagged energy sales. The sales-for-resale model

includes binaries, heating and cooling degree-days, lagged error terms and lagged energy

sales.

2.3.3 Long-term Forecasting Models

The goal of the long-term forecasting models is to produce a reasonable load

outlook for up to 30 years in the future. Given that goal, the long-term forecasting models

employ a full range of structural economic and demographic variables, electricity and

natural gas prices, weather as measured by annual heating and cooling degree-days, and

binary variables to produce load forecasts conditioned on the outlook for the U.S.

economy, for the Company's service-area economy, and for relative energy prices.

Most of the explanatory variables enter the long-term forecasting models in a

straightforward, untransformed manner. In the case of energy prices, however, it is

assumed, consistent with economic theory, that the consumption of electricity responds

to changes in the price of electricity or substitute fuels with a lag, rather than

instantaneously. This lag occurs for reasons having to do with the technical feasibility of

quickly changing the level of electricity use even after its relative price has changed, or

with the widely accepted belief that consumers make their consumption decisions on the

basis of expected prices, which may be perceived as functions of both past and current

prices.

35

KENTUCKY ER


There are several techniques, including the use of lagged price or a moving

average of price that can be used to introduce the concept of lagged response to price

change into an econometric model. Each of these techniques incorporates price

information from previous periods to estimate demand in the current period.

The general estimation period for the long-term load forecasting models was

1990-2012. The long-term energy sales forecast is developed by blending the last half of

the second year of the short-term forecast with the long-term forecast. The energy sales

forecast is developed by making a billed/unbilled adjustment to derive billed and accrued

values, which are consistent with monthly generation.

2.3.3.1 Supporting Models

In order to produce forecasts of certain independent variables used in the internal

energy requirements forecasting models, several supporting models are used, including a

natural gas price model and a regional coal production model for the Kentucky Power

service area. These models are discussed below.

2.3.3.1.1 Retail Natural Gas and Electricity Pricing Forecasts

In order to produce forecasts of certain independent variables used in the long-

term internal energy requirements forecasting models, a supporting forecast was

developed, i.e., a natural gas price forecast for the Company's service area.

The forecast price of natural gas used in Kentucky Power's energy models comes

from a forecast of state natural gas prices for four primary consuming sectors: residential,

commercial, industrial and electric utilities. The forecast of sectoral prices was assumed

to have the same growth as the East North Central region of the U.S. sectoral prices. The

regional U.S. natural gas price forecasts were obtained from U.S. DOE/EIA's 2013

Annual Energy Outlook.

The sectoral electricity prices are developed using internal information on

anticipated prices for the near-term. In the long-term, electricity price growth patterns

were obtained from U.S. Department of Energy / Energy Information Agency

(DOE/EIA)'s 2013 Annual Energy Outlook.

36

I a; KENTUCKY i'mm• POWER


2.3.3.1.2 Regional Coal Production Model

A regional coal production forecast is used as an input in the mine power energy

sales model. In the coal model, regional production depends mainly on Eastern U.S. coal

production, as well as on binary variables that reflect the impacts of special occurrences,

such as strikes. In the development of the regional coal production forecast, projections

of Eastern U.S. coal production were obtained from U.S. DOE/EIA's "2013 Annual

Energy Outlook." The estimation period for the model was 1991-2012.

2.3.3.2 Residential Energy Sales (807 KAR 5:058 Sec. 7.4.e.)

Residential energy sales for Kentucky Power are forecasted using two models, the

first of which projects the number of residential customers, and the second of which

projects kWh usage per customer. The residential energy sales forecast is calculated as

the product of the corresponding customer and usage forecasts.

2.3.3.2.1 Residential Customer Forecasts

The long-term residential customer forecasting model is linear and monthly. The

model for the Company's service area is depicted as follows:

Customers = f (population, employment, customers _,)

The population provides a measure for household formation, while service area

employment provides a measure of economic growth in the region, which will also affect

customer growth. The lagged dependent variable captures the adjustment of customer

growth to changes in the economy. There are also binary variables to capture monthly

variations in customers, unusual data points and special occurrences.

The customer forecast is blended with the short-term residential customer forecast to

produce a final forecast.

2.3.3.2.2 Residential Energy Usage Per Customer

The residential usage model is estimated using a Statistically Adjusted End-Use

Model (SAE), which was developed by Itron, a consulting firm with expertise in energy

modeling. This model assumes that use will fall into one of three categories: heat, cool

37

fl!,1; KENTUCKY im POWER


and other. The SAE model constructs variables to be used in an econometric equation

like the following:

Use = f (Xheat, Xcool, Xother)

The Xheat variable is derived by multiplying a heating index variable by a heating

use variable. The heating index incorporates information about heating equipment

saturation; heating equipment efficiency standards and trends; and thermal integrity and

size of homes. The heating use variable is derived from information related to billing

days, heating degree-days, household size, personal income, gas prices and electricity

prices.

The Xcool variable is derived by multiplying a cooling index variable by a

cooling use variable. The cooling index incorporates information about cooling

equipment saturation; cooling equipment efficiency standards and trends; and thermal

integrity and size of homes. The cooling use variable is derived from information related

to billing days, heating degree-days, household size, personal income, gas prices and

electricity prices.

The Xother variable estimates the non-weather sensitive sales and is similar to the

Xheat and Xcool variables. This variable incorporates information on appliance and

equipment saturation levels; average number of days in the billing cycle each month;

average household size; real personal income; gas prices and electricity prices.

The appliance saturations are based on historical trends from Kentucky Power's

residential customer survey. The saturation forecasts and and efficiency trends are based

on DOE forecasts and analysis by Itron. The thermal integrity and size of homes are for

the East North Central Census Region and are based on DOE and Itron data.

The number of billing days is from internal data. Economic and demographic

forecasts are from Moody's Analytics and the electricity price forecast is developed

internally.

The SAE model is estimated using a linear regression model. It is a monthly

model for the period January 1995 through February 2013. This model incorporates the

effects of the Energy Policy Act of 2005 (EPAct 2005), the Energy Independence and

38

fKENTUCKY POWER

A unit otAmerican Electric Power 2013 Integrated Resource Plan

Security Act of 2007 (EISA 2007), American Recovery and Reinvestment Act of 2009

(ARRA) and Energy Improvement and Extension Act of 2008 (EIEA 2008) on the

residential energy.

The long-term residential energy sales forecast is derived by multiplying the

"blended" customer forecast by the usage forecast from the SAE model.

2.3.3.3 Commercial Energy Sales (807 KAR 5:058 Sec. 7.4.e.)

Long-term commercial energy sales are forecast using a SAE model. This model

is similar to the residential SAE model. The functional model is as follows:

Energy = f (Xheat, Xcool, Xother)

As with the residential model, Xheat is determined by multiplying a heating index by

a heat use variable. The variables incorporate information on heating degree-days,

heating equipment saturation, heating equipment operating efficiencies, square footage,

average number of days in a billing cycle, commercial output, population and electricity

price.

The Xcool variable uses measures similar to the Xheat variable, except it uses

information on cooling degree-days and cooling equipment, rather than those items

related to heating load.

The Xother variable measures the non-weather sensitive commercial load. It uses

non-weather sensitive equipment saturations and efficiencies, as well as billing days,

commercial output and electricity price information.

The saturation, square footage and efficiencies are from the Itron base of DOE data

and forecasts. The saturations and related items are from DOE's 2012 Annual Energy

Outlook. Billing days and electricity prices are developed internally. The commercial

output measure is real commercial gross regional product from Moody's Analytics. The

equipment stock and square footage information are for the East North Central Census

Region.

39

1;1. KENTUCKY •■°, POWER


The SAE is a linear regression for the period January 2000 through February 2013.

As with the residential SAE model, the effects of EPAct 2005, EISA 2007, ARRA and

EIEA 2008 are captured in this model.

2.3.3.4 Industrial Energy Sales

2.3.3.4.1 Manufacturing

Manufacturing energy sales are estimated using a quarterly model, which is depicted as follows:

Energy = f (electricprice, metal sin dex, gipmanufacturing)

The manufacturing forecasting model relates energy sales to real price of

electricity, FRB production indexes for primary metals, gross regional product for

manufacturing and binary variables. The prices are modeled using 36-month moving

averages. The dependent and independent variables are modeled in logarithmic form.

2.3.3.4.2 Mine Power

Mine Power energy sales are estimated using a quarterly model, which is depicted

as follows:

Energy = f (electricprice, coalproduction)

The forecast of Kentucky Power's mine power energy consumption for non-

associated mining companies is produced with a model relating mine power energy sales

to regional coal production and a 36-month moving average of electric price to mine

power customers. This model is specified as linear, with the dependent and independent

variables in logarithmic form.

2.3.3.5 All Other Energy Sales

The forecast of public street and highway lighting relates energy sales to service

area commercial employment and binary variables. The model is specified as linear with

the dependent and variable in linear form and the independent variable in logarithmic

form.

40

fLii KENTUCKY mow POWER'


The municipal energy sales model is specified as linear. Municipal energy sales

are modeled relating energy sales to service area gross regional product, electricity

prices, heating and cooling degree-days and binary variables.

2.3.3.6 Blending Short- and Long-Term Sales

Values for the portion of the forecast horizon from March 2013 to December

2014 are generally taken from the short-term process. Values for the period of January

2015 to June 2015 are generally obtained by blending the results from the short-term and

long-term models. This blending process combines the two forecasts by assigning

weights to each forecasted value where these weights transition from favoring the short-

term values initially to favoring the long-term values by the end of the blending period.

Beyond the blending period, the long-term values are utilized. However, in the case of

Kentucky Power, two of the retail classes (industrial and other ultimate) and one of the

wholesale customers utilized the long-term forecast throughout the forecast horizon in

order to best utilize the long-term methodology's capability of anticipating turning points

in economic growth.

2.3.3.7 Billed/Unbilled and Losses

a. Billed/Unbilled Analysis

Unbilled energy sales are forecast using the same methodology that is used by the

Company to compute actual unbilled sales each month as part of its closing process. The

Company starts with the projected monthly internal energy requirements forecast,

subtracts the forecasted billed sales and estimate for line losses to derive the forecasted

net unbilled sales.

b. Losses and Unaccounted-For Energy

Energy is lost in the transmission and distribution of the product. This loss of

energy from the source of production to consumption at the premise is measured as the

average ratio of all FERC revenue class energy sales measured at the premise meter to

the net internal energy requirements metered at the source. In modeling, Company loss

study results are incorporated to apply losses to each revenue class.

41

KENTUCKY mm POWER



2.4 Forecast Methodology for Seasonal Peak Internal Demand

(807 KAR 5:058 Sec. 5.2. and Sec. 7.7.b and c.)

The demand forecast model is a series of algorithms for allocating the monthly

blended FERC revenue class sales to hourly demand. The inputs into forecasting hourly

demand are blended FERC revenue class sales, energy loss multipliers, weather, 24-hour

load profiles and calendar information.

The weather profiles are developed from representative weather stations in the

service area. Twelve monthly profiles of average daily temperature that best represent the

cooling and heating degree-days of the specific geography are taken from the last 30

years of historical values. The consistency of these profiles ensures the appropriate

diversity of the company loads.

The 24-hour load profiles are developed from historical hourly company or

jurisdictional load and end-use or revenue class hourly load profiles. The load profiles

were developed from segregating, indexing and averaging hourly profiles by season, day

types (weekend, midweek and Monday/Friday) and average daily temperature ranges.

The end-use and class profiles were obtained from Itron, Inc. Energy Forecasting load

shape library and modeled to represent each company or jurisdiction service area.

In forecasting, the weather profiles and calendars dictate which profile to apply

and the sales plus losses results dictate the volume of energy under the profile. In the end,

the profiles are benchmarked to the aggregate energy and seasonal peaks through the

adjustments to the hourly load duration curves of the annual 8,760 hourly values. These

8,760 hourly values per year are the forecast load of the individual companies of AEP-

East that can be aggregated by hour to represent load across the spectrum from end-use

or revenue classes to total AEP in the NM AEP Zone. Net internal energy requirements

are the sum of these hourly values to a total company energy need basis. Company peak

demand is the maximum of the hourly values from a stated period (month, season or

year).

42

KENTUCKY ER


2.5 Load Forecast Results

2.5.1 Load Forecast Including Approved EE Impacts (Base Forecast)

(807 KAR 5:058 Sec. 7.1.c.-g., Sec. 7.3, Sec. 7.4.a-d, Sec.7.5.b.1.-2.)

Exhibit 2-2 presents Kentucky Power's annual internal energy requirements,

disaggregated by major category (residential, commercial, industrial and other internal

sales, as well as losses) on an actual basis for the years 2008-2012 and on a forecast basis

for the years 2014-2028, with 2013 data being nine months actual and three months

forecast. The exhibit also shows annual growth rates for both the historical and forecast

periods. Please note that the residential load is forecast in aggregate and the distinction

between heating and non-heating load is reflected in the heating saturations contained in

the SAE model.

Exhibit 2-3 shows for Kentucky Power actual and forecasted summer, winter and

annual peak internal demands, along with annual total energy requirements. Also shown

are the associated growth rates and annual load factors.

Exhibit 2-4 shows further disaggregation of Kentucky Power's forecasted annual

internal energy requirements, along with the associated summer and winter peak

demands. Exhibits 2-5 and 2-6 show, for the first two full years of the forecast period,

i.e., 2014 and 2015, Kentucky Power's disaggregated energy requirements on a monthly

basis, along with monthly peak demands.

2.5.2 Load Forecast Excluding EE Impacts

(807 KAR 5:058 Sec. 7.1.c-g., Sec. 7.2.g., Sec. 7.3. and Sec. 7.4.a.-d, Sec. 7.5.b.1 and Sec. 7.5.b.2. and Sec. 8.4.a.6.)

Exhibit 2-7 lists the approved EE adjustments (discussed in Chapter 3) that were

used in the base forecasts of internal energy requirements and seasonal peak internal

demands by the Company. The resulting forecasts, which reflect the load prior to these

adjustments, are presented in Exhibits 2-8 through 2-12 in the same order as Exhibits 2-2

to 2-6.

43

KENTUCKY 11 POWER


2.6 Impact of Conservation and Demand-Side Management

(807 KAR 5:058 Sec. 7.4.d.)

Since the mid-1970s, conservation, caused in part by higher energy prices and in

part by Company-sponsored conservation and DSM programs, has reduced the rate of

growth of energy sales and peak demand on the entire AEP System and its operating

companies.

Higher energy prices and regulatory requirements have stimulated technological

improvements in the EE of new electric appliances and industrial machinery, and in the

thermal integrity of residential and commercial structures. The effect of these

improvements has been to decrease average electricity consumption per customer. It is

also believed that higher energy prices have had the effect of inducing a permanent

change in consumer attitudes toward energy conservation, which has tended to reduce

average energy consumption at all levels of price and technological development.

The Company has recognized both its responsibility to encourage its customers to

make wise use of all energy resources, and its expertise in the field of energy

consumption planning, and has for some years pursued the policy of providing its

customers with opportunities to use energy wisely. It has done so through both

educational programs and active promotional programs aimed at broad customer groups.

And, through its DSM programs, the Company has maintained an active interest and

participation in various programs for improving the cost-effectiveness of customer

electricity use. Descriptions of the Company's efforts in this regard are given in Chapter 3

of this report.

As for the load forecast, the impact of conservation on load is captured by the

inclusion of energy price variables in the forecasting equations. The impact of past

customer conservation and load management activities, including embedded EE

installations, is part of the historical record of electricity use, and, in that sense, is

intrinsically reflected in the load forecast. The load impacts of approved EE installations

are analyzed and projected separately, and appropriate adjustments are made to derive the

base load forecast.

44

KENTUCKY 1■• POWER'


The use of the SAE models for the residential and commercial sectors has enabled

the Company to capture the anticipated effects of EPAct 2005, EISA 2007, ARRA and

EIEA 2008. The SAE models reflect not only equipment efficiencies, but also factors

related to the building stock. These models reflect the EIA assessment of efficiency

trends as provided in the 2012 Annual Energy Outlook.

2.7 Energy-Price Relationships

(807 KAR 5:058 Sec. 7.7.e.1.)

An understanding of the relationship between energy prices and energy

consumption is crucial to developing a forecast of electricity consumption. In theory, the

effect of a change in the price of a good on the consumption of that good can be

disaggregated into two effects, the "income" effect and the "substitution" effect. The

income effect refers to the change in consumption of a good attributable to the change in

real income incident to the change in the price of that good. For most goods, a decline in

real income would induce a decline in consumption. The substitution effect refers to the

change in the consumption of a good associated with the change in the price of that good

relative to the prices of all other goods. The substitution effect is assumed to be negative

in all cases; that is, a rise in the price of a good relative to other, substitute goods would

induce a decline in consumption of the original good. Thus, if the price of electricity

were to rise, the consumption of electricity would fall, all other things being equal. Part

of the decline would be attributable to the income effect; consumers must make decisions

on how to allocate their budget to purchase electricity services and other goods and

services after the price of electricity rises. Part would be attributable to the substitution

effect; consumers would substitute relatively cheaper fuels for electricity once its price

had risen.

The magnitude of the effect of price changes on consumption differs over

different time horizons. In the short-term, the effect of a rise in the price of electricity is

severely constrained by the ability of consumers to substitute other fuels or to incorporate

more electricity-efficient technology. (The fact that the Company's short-term energy

45

ati KENTUCKY POWER


consumption models do not include price as an explanatory variable is a reflection of the

belief that this constraint is severe).

In the long-term, however, the constraints on substitution are lessened for a

number of reasons. First, durable equipment stocks begin to reflect changes in relative

energy prices by favoring the equipment using the fuel that was expected to be cheaper;

second, heightened consumer interest in saving electricity, backed by willingness to pay

for more efficiency, spurs development of conservation technology; third, existing

technology, too expensive to implement commercially at previous levels of energy prices,

becomes feasible at the new, higher energy prices; and fourth, normal turnover of

electricity-using equipment contributes to a higher average level of EE. For these

reasons, energy price changes are expected to have an effect on long-term energy

consumption levels. As a reflection of this belief, most of the Company's long-term

forecasting models, including the residential, commercial, manufacturing and mine

power energy sales models, directly incorporate the price of electricity as an explanatory

variable. In these cases, the coefficient of the price variable provides a quantitative

measure of the sensitivity of the forecast value to a change in price. The residential

models also incorporate the price of natural gas to consumers in the state of Kentucky.

For these reasons, energy price changes are expected to have an effect on long-

term energy consumption levels. As a reflection of this belief, most of the Company's

long-term forecasting models, including the residential, commercial, manufacturing and

mine power energy sales models, incorporate the price of electricity as an explanatory

variable. The residential Statistically Adjusted End-Use (SAE) Model uses price in

development of explanatory variables. There are a variety of short- and long-run

elasticities utilized in this analysis. In addition to electricity prices, the residential SAE

model utilizes the price of natural gas and associated cross-price elasticities. Likewise,

the commercial SAE model incorporates electricity price and an associated price

elasticity to develop explanatory variables. Manufacturing and mine power have price as

an explanatory variable. In these cases, the coefficient of the price variable provides a

quantitative measure of the sensitivity of the forecast value to a change in price.

46

KENTUCKY ER


2.8 Forecast Uncertainty and Range Of Forecasts

(807 KAR 5:058 Sec. 7.7.d.)

Even though load forecasts are created individually for each of the operating

companies in the AEP-East Zone, and aggregated to form the AEP—East Zone total,

forecast uncertainty is of primary interest at the System level, rather than the operating

company level. Thus, regardless of how forecast uncertainty is characterized, the analysis

begins with AEP-East Zone load.

Among the ways to characterize forecast uncertainty are: (1) the establishment of

confidence intervals with a given percentage of possible outcomes, and (2) the

development of high- and low-case scenarios that demonstrate the response of forecasted

load to changes in driving-force variables. Kentucky Power continues to support both

approaches. However, this report uses scenarios for capacity planning sensitivity

analyses.

The first step in producing high- and low-case scenarios was the estimation of an

aggregated "mini-model" of AEP System—East Zone internal energy requirements. This

approach was deemed more feasible than attempting to calculate high and low cases for

each of the many equations used to produce the load forecasts for all operating

companies. The mini-model is intended to represent the full forecasting structure

employed in producing the base-case forecast for the AEP System—East Zone and, by

association, for the Company. The dependent variable is total AEP System—East Zone

internal energy requirements, excluding sales to the two aluminum reduction plants in the

AEP System—East Zone service area. This aluminum load is a large and volatile

component of total load, which is treated judgmentally, not analytically, in the load

forecast. It is simply added back to the alternative forecasts produced by the mini-model

to create low- and high-case scenarios for total internal energy requirements. The

independent variables are real service area gross regional product (GRP), the average real

price of electricity to all AEP System—East Zone customer classes, the average real price

of natural gas in the seven states served by AEP System—East Zone, and AEP System—

East Zone service-area heating and cooling degree-days. Acceptance of this particular

specification was based on the usual statistical tests of goodness-of-fit, on the

47

► KENTUCKY POWER A unit ofAmerican Electric Power


reasonableness of the elasticity's derived from the estimation, and on a rough agreement

between the model's load prediction and that produced by the disaggregated modeling

approach followed in producing the base load forecast.

Once a base-case energy forecast had been produced with the mini-model, low

and high values for the independent variables were determined. The values finally

decided upon reflected professional judgment. The low- and high-case growth rates in

real GRP for the forecast period were 1.1% and 2.3% per year, respectively, compared to

1.8% for the base case. Real electricity price high and low cases assumed average annual

growth rates of 0.5% and 0.3%, respectively. Meanwhile, the base case for real electricity

price assumed an average annual growth of 0.4%. Variations in weather were not

considered, thus the value of heating and cooling degree-days remained the same in all

cases.

For Kentucky Power, the low-case and high-case energy and peak demand

forecasts for the last forecast year, 2028, represent deviations of about 8% below and 6%

above, respectively, the base-case forecast. In this regard, the low-case and high-case

growth rates in summer peak internal demand for the forecast period were -0.3% and

0.7% per year, respectively, compared to 3% per year for the base case.

The low-case, base-case and high-case forecasts of summer and winter peak

demands and total energy requirements (including approved EE impacts) for Kentucky

Power are tabulated in Exhibits 2-13. Graphical displays of the range of forecasts of

internal energy requirements and summer peak demand for Kentucky Power are shown in

Exhibit 2-14.

The corresponding range of load forecasts excluding approved EE impacts is

shown in Exhibits 2-15.

48

KENTUCKY ER


2.9 Significant Changes from Previous Forecast

(807 KAR 5:058 Sec. 6)

2.9.1 Energy Forecast

During the four years since the last IRP filing with the Commission, the nation's

and Kentucky Power's service areas economies have all experienced significant changes

and therefore the load forecast for Kentucky Power reflects a more modest outlook.

Exhibit 2-16 provides a tabular comparison of the 2009 and 2013 forecasts of

total internal energy requirements (including EE impacts). Exhibit 2-17 shows the

comparison for Kentucky Power in graphical form. As these exhibits indicate, Kentucky

Power's 2013 energy forecast is lower than the 2009 forecast in terms of magnitude

(1,950 GWh, or 21.7%, lower for year 2023) and long-term average annual growth rate

(0.2% vs. 0.7%).

An examination of the sectoral changes in the Kentucky Power forecast may

provide a better understanding of the changes in the aggregate forecast. The forecasted

levels of the sectoral components for the year 2023 did not change uniformly with the

21.7% decrease in the forecast of total energy requirements. Specifically, the residential,

commercial and industrial energy sales forecasts were decreased by 9.7%, 19.2%, and

25.7%, respectively, while the losses forecast was decreased by 46.0%.

Factors contributing to the decrease in the residential and commercial energy

sales forecasts include impacts of a sluggish economy, deteoriating residential customer

base, a re-evaluation of expected long-term trends in residential and commercial

consumption patterns in light of what has been experienced historically. The changed

assumptions reflect the effect of updated information obtained or developed since the

2009 forecast, along with changing perceptions of the future.

For the industrial sector, the decrease reflects more recent trends that have

evolved since the 2008-09 recession. In addition, the coal industry faces more downward

pressures that have negatively affected the forecast.

49

KENTUCKY ER


2.9.2 Peak Internal Demand Forecast

Exhibit 2-18 provides a tabular comparison of the 2009 and 2013 forecasts of the

winter and summer peak internal demand (including EE impacts) for both. This exhibit

indicates that for the winter of 2023/24, Kentucky Power's 2013 peak demand forecast is

20.1% lower than the 2009 forecast. Likewise, the Company's 2013 peak demand

forecast for summer 2023 is 22.0 % lower than 2009 forecast. These decreases reflect the

change in the forecast for total energy requirements and an evaluation of the weather

normal peak experience.

2.9.3 Forecasting Methodology

(807 KAR 5:058 Sec. 7.7.f)

Opportunities to enhance forecasting methods are explored by Kentucly Power on

a continuing basis. The Company evaluates each sector for changing growth patterns and

determines the factors that may be the underlying causes for such changes. For example,

the industrial forecast was lowered due to a changing economic landscape and

diminished expectations for the coal industry.

2.10 Additional Load Information

(807 KAR 5:058 Sec. 7.1.a. and b., Sec. 7.2.a-f. and h., Sec. 7.5.a.1 and 2 and Sec. 7.7.g.)

Additional information provided for the purposes of this report includes the

following:

® Exhibit 2-19: Kentucky Power, Average Annual Number of Customers by Class,

2008-2012.

® Exhibits 2-20 and 2-21: Kentucky Power, Annual Internal Load by Class

(GWh), 2008-2012.

® Exhibits 2-22 and 2-23: Kentucky Power Recorded and Weather-Normalized

Peak Internal Load (MW) and Energy Requirements (GWh), 2008-2012. In

addition, Normalized Annual Internal Sales by Class (GWh), 2008-2012.

• Exhibit 2-24: Kentucky Power, Profiles of Monthly Peak Internal Demands,

2007 2012 (Actual), 2022 and 2027.

The historical profiles presented in Exhibit 2-22 have not been adjusted to reflect

normal weather patterns and, therefore, may vary to some degree from the forecast

50

LE; KENTUCKY m"•• POWER


patterns projected for 2022 and 2027. These patterns also reflect the expectation that

Kentucky Power will continue to experience its annual peak demand in the winter season.

Currently, the Company has one customer with interruptible provisions in its

contracts. The Company conducted its most recent residential customer survey in the

winter of 2013. However, the survey was not completed in time to be used in the load

forecast contained in this report and the previous survey was relied upon. As in the past,

this updated survey will provide information on appliance saturations, along with other

useful information to better understand the residential load.

2.11 Data-Base Sources

Sources from within the Company that were used in developing the Company's

load forecasts are as follows:

1. Sales for Resale Reports (Form ST-18);

2. daily, monthly and annual System Operation Department reports;

3. monthly financial reports;

4. monthly kWh and revenue SIC reports; and

5. residential tariff schedules and fuel clause summaries for all operating companies.

The data sources from outside the Company are varied and include state and

federal agencies, as well as Moody's Analytics. Exhibit 2-25 identifies the data series

and associated sources, along with notes on adjustments made to the data before

incorporation into the load forecasting models.

2.12 Other Topics

2.12.1 Residential Energy Sales Forecast Performance

Exhibit 2-26 provides a comparison of actual vs. the 2009 forecast of Kentucky

Power's residential energy sales for the years 2009-2012. The gap between actual and

forecast residential energy sales generally widened over the four-year period. During this

period the number of residential customers declined. Another factor affecting sales is the

impact of more stringent efficiency standards being mandated by Congress. Both of these

factors will continue to have major influences on residential energy sales over the

forecast period.

51

r7 KENTUCKY POWER A unit of American Electric Power


2.12.2 Peak Demand Forecast Performance

Exhibit 2-27 provides a comparison of actual vs. the 2009 forecast of Kentucky

Power's seasonal internal peak demands for 2009-2012. The exhibit also compares the

calculated weather-normalized demands with the forecast values, thus indicating the

extent to which weather affected actual demands.

There have been many changes in the local service over the four years since the

2009 forecast was filed. For, example the residential customer base has eroded, there

have been additional energy legislation enacted and the commercial and industrial sectors

experienced load decreases between 2009 and 2012. Items, such as these, have

contributed to a diminished outlook for peak demand growth. In addition, recent trends in

normalized demand growth are evaluated when developing the forecast.

2.12.3 Forecast Updates

(807 KAR 5:058 Sec. 7.6.)

Each year the Company provides updates to the load forecast in response to

requests related to Administrative Case 387.

2.12.4 KPSC Staff Issues Addressed

On March 4, 2011, the Commission issued their Staff's report on Kentucky Power's

2009 IRP and requested that the Company address certain issues in its next IRP report

(this report). The following issues pertaining to load forecasting are restated from the

Staff report and addressed below:

1. Kentucky Power should consider disaggregating its residential customer

class in its SAE models to gain further insight into usage patterns and future

energy needs. Disaggregating the commerical class may also provide

additional insights.

The Company has disaggrated its residential forecast into heating, cooling,

lighting and other energy, Also, the Company has disaggregated its commercial

sector into heating, cooling and other energy. Both of these disaggregations are

used in the development of the peak demand forecast.

52



2. Provide a comparison of forecasted winter and summer peak demands with

actual results for the period following Kentucky Power's 2009 IRP, along

with a discussion of the reasons for the differences between forecasted and

actual peak demands.

See Section 2.12.2 where this issue has been addressed.

3. Provide a comparison of the annual forecast of residential energy sales, using

the current econometric models, with actual results for the period following

the 2009 IRP. Include a discussion of the reasons for the differences between

forecasted and actual results.

See Section 2.12.1 where this issue has been addressed.

4. Given that Kentucky Power's service area economy is not expected to

perform as well as the rest of the region, the possibilityof either federal

emissions-limiting legislation or targeted EPA actions limiting various

emissions may have significant impacts on Kentucky Power's service

territory. In its next IRP, Kentucky Power should explicitly account for

potential federal legislation imposing stricter emissions limits on its

generation in its forecasts and risk analysis. Potential EPA actions limiting

emissions should also be explicitly accounted for in the forecasts and risk

analysis.

The Company's risk analysis for its resource portfolio considers the impacts of

various Federal mandates. The load forecast includes an outlook of rising prices

over the forecast horizon, which were determined by internal company

information and EIA price outlook in the longer term. The timing and impact of

specific rules and regulations have not been evaluated, but rising prices are

consistent with more stringent environmental standards.

53

Blending Process

Hourly Demand Models (Load Shapes)

Losses, Billed/Unbilled Adjustments

Peak Demand and Internal Energy

Requirements Forecast

Long-Term Energy Models

Short-Term Energy Models

Moody's Analytics

National & Regional Economic Forecasts

Monthly Energy Sales & Weather

History

DOE/EIA Annual Energy Outlook

Monthly Model Input

History

Electricity Price

Forecast

Regional Coal

Production

State Gas Price

Forecast

Residential & Commercial SAE Models

• •

fKENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

2.13 Chapter 2 Exhibits

The exhibits related to Chapter 2 follow:

Exhibit 2-1(a)

Kentucky Power Company Internal Energy Requirements and Peak Demand

Forecasting Method

54


Exhibit 2-1(b) KENTUCKY POWER COMPANY

VARIABLES EMPLOYED IN FORECAST MODELS OF ENERGY SALES

Variable

Residential Customers

Residential Energy Sales

Commercial Customers

Commercial Energy Sales

Manufacturing Energy Sales

Mine Power Energy Sales

All Other Energy Sales

Short Term

Long Term

Short Term

Long Term

Short Term

Short Term

Long Term

Short Term

Long Term

Short Term

Long Term

Short Term

Long Term

Binary X X X X X '' X X X X X X X X

Time Trend X X X X X X X X

Electricity Price X X X X X

Natural Gas Price X X

Residential Appliance Saturations X

Service Area Employment X

Service Area Personal Income X

Service Area Population X X X

Residential Customers X

Heating Degree-Days X X X X X X

Cooling Degree-Days X X X X X

Gross Regional Product X X X

FRB Industrial Production Index X

Commercial Employment X

Coal Production X

55

KENTUCKY



Exhibit 2-2 Kentucky Power Company

Annual Internal Energy Requirements and Growth Rates 2008-2028

Including EE Impacts

Residential Sales

Commercial Sales

Industrial Sales

Other Internal Sales Losses

Total Internal Energy Requirements

Actual GWH % Growth GWH % Growth GWH % Growth GWH % Growth GWH % Growth GWH %Growth

2008 2,481 - 1,429 - 3,322 - 110 - 568 - 7,910 - 2009 2,426 -2.2 1,426 -0.2 3,206 -3.5 104 -5.7 395 -30.5 7,557 -4.5 2010 2,614 7.7 1,469 3.0 3,256 1.5 112 7.5 474 20.1 7,924 4.9 2011 2,342 -10.4 1,381 -6.0 3,250 -0.2 105 -6.4 470 -0.8 7,548 -4.8 2012 2,241 -4.3 1,350 -2.2 3,060 -5.9 105 0.0 400 -15.0 7,155 -5.2

Forecast 2013 (1) 2,292 2.3 1,337 -0.9 2,895 -5.4 105 0.0 464 16.1 7,093 -0.9

2014 2,267 -1.1 1,346 0.7 2,828 -2.3 106 1.6 410 -11.7 6,958 -1.9 2015 2,247 -0.9 1,351 0.3 2,838 0.3 107 1.0 410 0.0 6,953 -0.1 2016 2,245 -0.1 1,355 0.3 2,853 0.5 109 1.1 409 -0.2 6,970 0.3 2017 2,236 -0.4 1,359 0.3 2,866 0.5 109 0.6 405 -1.1 6,975 0.1 2018 2,231 -0.2 1,361 0.1 2,869 0.1 110 0.5 407 0.6 6,979 0.1 2019 2,231 0.0 1,364 0.2 2,873 0.1 110 0.5 407 -0.1 6,986 0.1 2020 2,226 -0.2 1,368 0.3 2,883 0.3 111 0.5 410 0.7 6,997 0.2 2021 2,225 0.0 1,376 0.6 2,893 0.4 112 0.5 406 -0.9 7,012 0.2 2022 2,223 -0.1 1,382 0.5 2,910 0.6 112 0.5 409 0.7 7,036 0.3 2023 2,222 0.0 1,390 0.6 2,921 0.4 113 0.5 411 0.4 7,056 0.3 2024 2,223 0.0 1,398 0.6 2,927 0.2 113 0.4 411 0.1 7,072 0.2 2025 2,225 0.1 1,408 0.7 2,932 0.2 114 0.4 410 -0.2 7,090 0.2 2026 2,227 0.1 1,418 0.7 2,941 0.3 114 0.4 412 0.4 7,112 0.3 2027 2,229 0.1 1,426 0.6 2,949 0.3 115 0.4 415 0.9 7,134 0.3 2028 2,234 0.2 1,436 0.7 2,957 0.3 115 0.3 416 0.1 7,158 0.3

Average Annual Growth Rates: 2008-2012 -2.5 -1.4 -2.0 -1.3 -8.4 -2.5 2014-2028 -0.1 0.5 0.3 0.6 0.1 0.2

Note: (1) Data for 2013 are nine months actual and three months forecast.

56

KENTUCKY POWER




Seasonal and Annual Peak Demands, Energy Requirements and Load Factor 2008-2028


Summer Peak Winter Peak (1) Annual Peak, Energy and Load Factor

MW %Growth GWH %Growth Load

Factor % Date MW %Growth Date MW %Growth Actual

2008 06/09/08 1,249 - 01/16/09 1,674 - 1,678 - 7,910 - 53.7 2009 08/10/09 1,163 -6.9 01/08/10 1,543 -7.8 1,674 -0.2 7,557 -4.5 51.5 2010 08/04/10 1,310 12.6 12/15/10 1,596 3.4 1,596 -4.7 7,924 4.9 56.7 2011 07/11/11 1,240 -5.3 01/04/12 1,378 -13.7 1,522 -4.6 7,548 -4.8 56.6 2012 06/29/12 1,183 -4.6 01/23/13 1,409 2.2 1,378 -9.5 7,155 -5.2 59.1

Forecast 2013 (2) 1,138 -3.8 1,432 1.6 1,409 2.2 7,093 -0.9 57.5

2014 1,132 -0.5 1,431 -0.1 1,432 1.6 6,958 -1.9 55.5 2015 1,133 0.1 1,432 0.1 1,431 -0.1 6,953 -0.1 55.5 2016 1,134 0.1 1,431 0.0 1,432 0.1 6,970 0.3 55.6 2017 1,137 0.2 1,431 0.0 1,431 0.0 6,975 0.1 55.6 2018 1,139 0.2 1,432 0.1 1,431 0.0 6,979 0.1 55.7 2019 1,141 0.2 1,430 -0.1 1,432 0.1 6,986 0.1 55.7 2020 1,142 0.1 1,436 0.4 1,430 -0.1 6,997 0.2 55.8 2021 1,149 0.6 1,439 0.2 1,436 0.4 7,012 0.2 55.7 2022 1,154 0.4 1,438 0.0 1,439 0.2 7,036 0.3 55.8 2023 1,157 0.2 1,438 -0.1 1,438 0.0 7,056 0.3 56.0 2024 1,158 0.1 1,444 0.5 1,438 -0.1 7,072 0.2 56.2 2025 1,166 0.6 1,448 0.3 1,444 0.5 7,090 0.2 56.0 2026 1,171 0.4 1,452 0.3 1,448 0.3 7,112 0.3 56.0 2027 1,176 0.5 1,454 0.1 1,452 0.3 7,134 0.3 56.1 2028 1,179 0.3 1,459 0.4 1,454 0.1 7,158 0.3 56.2

Average Annual Growth Rates: 2008-2012 -1.3 -4.2 -4.8 -2.5 2014-2028 0.3 0.1 0.1 0.2

Notes: (1) Actual winter peak for year may occur in the 4th quarter of that year or in the 1st quarter of the following year. (2) Data for 2013 are nine months actual and three months forecast.

:■ • MINCH=

57

KENTUCKY POWER



Annual Internal Load 2014-2023


2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Internal Energy (GWH)

2,267 2,247 2,245 2,236 2,231 2,231 2,226 2,225 2,223 2,222 2,223 2,225 2,227 2,229 2,234 Residential

Commercial 1,346 1,351 1,355 1,359 1,361 1,364 1,368 1,376 1,382 1,390 1,398 1,408 1,418 1,426 1,436

Industrial 2,828 2,838 2,853 2,866 2,869 2,873 2,883 2,893 2,910 2,921 2,927 2,932 2,941 2,949 2,957

Total Other Ultimate 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11

Total Ultimate Sales 6,453 6,446 6,463 6,472 6,472 6,479 6,487 6,505 6,525 6,544 6,559 6,577 6,597 6,615 6,638

Municipals 96 97 98 98 99 100 100 101 101 102 102 103 103 104 104

Total Sales-for-Resale 96 97 98 98 99 100 100 101 101 102 102 103 103 104 104

Total Internal Sales 6,548 6,543 6,561 6,570 6,571 6,579 6,588 6,605 6,627 6,646 6,661 6,680 6,700 6,719 6,742

Total Losses 410 410 409 405 407 407 410 406 409 411 411 410 412 415 416

Total Internal Energy 6,958 6,953 6,970 6,975 6,979 6,986 6,997 7,012 7,036 7,056 7,072 7,090 7,112 7,134 7,158

Internal Peak Demand (MW)

1,132 1,133 1,134 1,137 1,139 1,141 1,142 1,149 1,154 1,157 1,158 1,166 1,171 1,176 1,179 Summer Preceding Winter 1,431 1,432 1,431 1,431 1,432 1,430 1,436 1,439 1,438 1,438 1,444 1,448 1,452 1,454 1,459

846101E1

58

KENTUCKY POWER




Monthly Internal Load 2014


Internal Energy (GWH) Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Annual

Residential 302.5 232.8 216.3 136.9 133.1 154.3 190.4 184.2 141.5 142.4 171.3 261.6 2,267

Commercial 126.1 105.3 112.3 98.8 109.2 114.2 121.0 117.1 106.7 118.8 102.3 114.4 1,346

Industrial 234.9 219.9 242.8 233.9 247.9 232.6 225.9 235.3 213.4 256.1 245.5 240.2 2,828

Total Other Ultimate 1.1 0.9 0.9 0.8 0.8 0.7 0.7 0.8 0.8 1.0 1.0 1.1 11

Total Ultimate Sales 664.6 558.8 572.3 470.4 491.0 501.8 538.0 537.5 462.5 518.4 520.1 617.2 6,453

Municipals 10.6 8.6 7.9 6.9 6.6 7.4 8.6 8.5 7.0 7.1 7.6 9.0 96 Total Sales-for-Resale 10.6 8.6 7.9 6.9 6.6 7.4 8.6 8.5 7.0 7.1 7.6 9.0 96

Total Internal Sales 675.2 567.4 580.2 477.3 497.6 509.1 546.6 545.9 469.5 525.5 527.7 626.2 6,548

Total Losses 54.0 45.3 16.9 38.3 20.1 40.9 30.2 43.8 37.7 -6.1 42.3 46.6 410

Total Internal Energy 729.2 612.7 597.1 515.6 517.6 550.0 576.8 589.8 507.2 519.4 570.0 672.8 6,958

Internal Peak Demand (MW) 1,300 1,432 1,176 986 931 1,032 1,132 1,063 967 910 1,096 1,247 1,432

59

fa 'LIMY PC FR A unit of American Electric Power






Residential 300.1 232.1 215.3 136.7 136.6 151.9 188.6 183.8 140.5 136.0 170.6 254.7 2,247

Commercial 125.3 104.3 111.4 98.2 114.3 116.2 120.4 116.8 106.7 118.5 103.7 115.0 1,351

Industrial 236.1 220.6 243.4 234.4 251.7 233.7 225.8 235.8 214.3 255.2 245.1 241.9 2,838





Total Losses 53.9 45.4 18.0 38.3 6.8 40.9 32.4 43.8 37.6 0.5 42.4 49.9 410



60

KENTUCKY POWER A unit otAmerican Electric Power 2013 Integrated Resource Plan


Estimated Approved EE Impacts on Forecasted Energy Requirements and Peak Demands

Energy Requirements Impacts GWH

Peak Demand Impacts MW

Year Residential Commercial Industrial Other Retail Losses Total Summer

Winter

Following

2013* 4 2 0 0 1 7 0 8

2014 30 12 0 0 4 46 5 11

2015 40 16 0 0 5 61 7 13

2016 47 20 0 0 6 73 9 15

2017 52 23 0 0 6 81 10 17

2018 55 25 0 0 7 87 11 18

2019 57 27 0 0 7 92 12 19

2020 58 29 0 0 7 94 12 20

2021 59 30 0 0 8 96 13 21

2022 59 30 0 0 8 97 13 21

2023 59 30 0 0 8 97 14 21

2024 59 30 0 0 8 97 14 21

2025 59 30 0 0 8 97 14 21

2026 59 30 0 0 8 97 14 21

2027 59 30 0 0 8 97 14 21

2028 59 30 0 0 8 97 14 21

Note: *Data for 2013 are three months forecast.

KENTUCKY POWER




Annual Internal Energy Requirements and Growth Rates 2008-2028

Excluding EE Impacts

Residential Sales

Commercial Sales

Industrial Sales

Other Internal Sales Losses

Total Internal Energy Requirements

Actual GWH % Growth GWH % Growth GWH %Growth GWH % Growth GWH %Growth GWH % Growth

2008 2,481 - 1,429 - 3,322 - 110 - 568 - 7,910 -- 2009 2,426 -2.2 1,426 -0.2 3,206 -3.5 104 -5.7 395 -30.5 7,557 -4.5 2010 2,614 7.7 1,469 3.0 3,256 1.5 112 7.5 474 20.1 7,924 4.9 2011 2,342 -10.4 1,381 -6.0 3,250 -0.2 105 -6.4 470 -0.8 7,548 -4.8 2012 2,241 -4.3 1,350 -2.2 3,060 -5.9 105 0.0 400 -15.0 7,155 -5.2

Forecast 2013 (1) 2,296 2.5 1,339 -0.8 2,895 -5.4 105 0.0 466 16.4 7,100 -0.8

2014 2,298 0.1 1,358 1.4 2,828 -2.3 106 1.6 414 -11.2 7,004 -1.4 2015 2,287 -0.5 1,367 0.6 2,838 0.3 107 1.0 415 0.3 7,014 0.1 2016 2,292 0.2 1,375 0.5 2,853 0.5 109 1.1 415 0.1 7,043 0.4 2017 2,288 -0.2 1,382 0.5 2,866 0.5 109 0.6 411 -1.0 7,056 0.2 2018 2,287 -0.1 1,386 0.3 2,869 0.1 110 0.5 414 0.7 7,066 0.1 2019 2,288 0.1 1,391 0.4 2,873 0.1 110 0.5 414 0.0 7,077 0.2 2020 2,284 -0.2 1,397 0.4 2,883 0.3 111 0.5 417 0.8 7,092 0.2 2021 2,284 0.0 1,405 0.6 2,893 0.4 112 0.5 414 -0.9 7,108 0.2 2022 2,282 -0.1 1,412 0.5 2,910 0.6 112 0.5 417 0.7 7,133 0.4 2023 2,281 0.0 1,420 0.6 2,921 0.4 113 0.5 418 0.4 7,154 0.3 2024 2,282 0.0 1,429 0.6 2,927 0.2 113 0.4 418 0.1 7,169 0.2 2025 2,285 0.1 1,439 0.7 2,932 0.2 114 0.4 418 -0.2 7,187 0.2 2026 2,287 0.1 1,448 0.6 2,941 0.3 114 0.4 419 0.3 7,209 0.3 2027 2,288 0.1 1,457 0.6 2,949 0.3 115 0.4 423 0.9 7,231 0.3 2028 2,294 0.2 1,466 0.6 2,957 0.3 115 0.3 423 0.1 7,255 0.3

Average Annual Growth Rates: 2008-2012 -2.5 -1.4 -2.0 -1.3 -8.4 -2.5 2014-2028 0.0 0.5 0.3 0.6 0.2 0.3

Note: Data for 2013 are nine months actual and three months forecast.

62

KENTUCKY POWER

A unit cl American Electric Power



Seasonal and Annual Peak Demands, Energy Requirements and Load Factor 2008-2028


Summer Peak Winter Peak (1) Annual Peak, Energy and Load Factor

MW %Growth GWH %Growth Load

Factor % Date MW %Growth Date MW %Growth Actual

2008 1,249 - 1,674 - 1,678 - 7,910 - 53.7 2009 1,163 -6.9 1,543 -7.8 1,674 -0.2 7,557 -4.5 51.5 2010 1,310 12.6 1,596 3.4 1,596 -4.7 7,924 4.9 56.7 2011 1,240 -5.3 1,378 -13.7 1,522 -4.6 7,548 -4.8 56.5 2012 1,183 -4.6 1,409 2.2 1,378 -9.5 7,155 -5.2 59.1

Forecast 2013 (2) 1,138 -3.8 1,440 2.2 1,409 2.2 7,100 -0.8 57.5

2014 1,137 0.0 1,442 0.1 1,440 2.2 7,004 -1.4 55.5 2015 1,140 0.2 1,445 0.2 1,442 0.1 7,014 0.1 55.5 2016 1,143 0.2 1,447 0.1 1,445 0.2 7,043 0.4 55.6 2017 1,147 0.3 1,448 0.1 1,447 0.1 7,056 0.2 55.7 2018 1,150 0.3 1,450 0.2 1,448 0.1 7,066 0.1 55.7 2019 1,153 0.3 1,449 -0.1 1,450 0.2 7,077 0.2 55.7 2020 1,155 0.2 1,456 0.5 1,449 -0.1 7,092 0.2 55.9 2021 1,162 0.6 1,460 0.3 1,456 0.5 7,108 0.2 55.7 2022 1,167 0.5 1,459 0.0 1,460 0.3 7,133 0.4 55.8 2023 1,170 0.3 1,459 -0.1 1,459 0.0 7,154 0.3 56.0 2024 1,172 0.1 1,465 0.5 1,459 -0.1 7,169 0.2 56.1 2025 1,179 0.6 1,470 0.3 1,465 0.5 7,187 0.2 56.0 2026 1,185 0.4 1,474 0.3 1,470 0.3 7,209 0.3 56.0 2027 1,190 0.4 1,475 0.1 1,474 0.3 7,231 0.3 56.0 2028 1,193 0.3 1,480 0.4 1,475 0.1 7,255 0.3 56.2

Average Annual Growth Rates: 2008-2012 -1.3 -4.2 -4.8 -2.5 2014-2028 0.3 0.2 0.2 0.3

Note: (1) Actual winter peak for year may occur in the 4th quarter of that year or in the 1st quarter of the following year. (2) Data for 2013 are nine months acutal and three months forecast.

63




Annual Internal Load 2012-2021


2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Internal Energy (GWH)

2,298 2,287 2,292 2,288 2,287 2,288 2,284 2,284 2,282 2,281 2,282 2,285 2,287 2,288 2,294 Residential

Commercial 1,358 1,367 1,375 1,382 1,386 1,391 1,397 1,405 1,412 1,420 1,429 1,439 1,448 1,457 1,466

Industrial 2,828 2,838 2,853 2,866 2,869 2,873 2,883 2,893 2,910 2,921 2,927 2,932 2,941 2,949 2,957

Total Other Ultimate 11 11 11 11 11 11 11 11 11 11 11 11 11 11 11

Total Ultimate Sales 6,495 6,503 6,530 6,547 6,553 6,564 6,574 6,593 6,615 6,634 6,649 6,667 6,687 6,705 6,728

Municipals 96 97 98 98 99 100 100 101 101 102 102 103 103 104 104 Total Sales-for-Resale 96 97 98 98 99 100 100 101 101 102 102 103 103 104 104

Total Internal Sales 6,591 6,599 6,628 6,645 6,652 6,663 6,675 6,694 6,716 6,735 6,751 6,769 6,790 6,809 6,832

Total Losses 414 415 415 411 414 414 417 414 417 418 418 418 419 423 423

Total Internal Energy 7,004 7,014 7,043 7,056 7,066 7,077 7,092 7,108 7,133 7,154 7,169 7,187 7,209 7,231 7,255

Internal Peak Demand (MW)

1,137 1,140 1,143 1,147 1,150 1,153 1,155 1,162 1,167 1,170 1,172 1,179 1,185 1,190 1,193 Summer Preceding Winter 1,442 1,445 1,447 1,448 1,450 1,449 1,456 1,460 1,459 1,459 1,465 1,470 1,474 1,475 1,480

64

. -WER A unit of American Electric Power






Residential 306.4 236.2 219.0 139.0 134.9 156.4 192.9 186.7 143.8 144.3 173.4 264.7 2,298

Commercial 127.3 106.3 113.3 99.8 110.2 115.2 122.1 118.2 107.8 119.8 103.2 115.4 1,358

Industrial 234.9 219.9 242.8 233.9 247.9 232.6 225.9 235.3 213.4 256.1 245.5 240.2 2,828





Total Losses 54.1 45.1 17.5 38.7 20.6 41.2 30.1 43.8 37.5 -5.5 43.2 47.3 414



65

'UCKY






Residential 305.2 236.6 219.0 139.6 139.0 154.5 191.8 187.1 143.4 138.3 173.4 258.8 2,287

Commercial 126.8 105.8 112.8 99.5 115.5 117.5 121.8 118.3 108.2 119.7 104.9 116.4 1,367

Industrial 236.1 220.6 243.4 234.4 251.7 233.7 225.8 235.8 214.3 255.2 245.1 241.9 2,838





Total Losses 54.1 45.1 18.7 38.8 7.5 41.3 32.4 43.7 37.4 1.3 43.6 50.7 415



66

KENTUCKY POWER




Low, Base and High Case for Forecasted Seasonal Peak Demands and Internal Energy Requirements

2014-2028


Year

Summer Peak Internal Demands (MW)

Winter (Following) Peak Internal Demands (MW)

Internal Energy Requirements (GWH)

Low Case

Base Case

High Case

Low Case

Base Case

High Case

Low Case

Base Case

High Case

2014 1,122 1,132 1,136 1,410 1,431 1,437 6,899 6,958 6,984 2015 1,116 1,133 1,138 1,397 1,432 1,445 6,850 6,953 6,984 2016 1,106 1,134 1,144 1,384 1,431 1,456 6,801 6,970 7,034 2017 1,099 1,137 1,156 1,374 1,431 1,466 6,744 6,975 7,095 2018 1,093 1,139 1,167 1,365 1,432 1,478 6,698 6,979 7,151 2019 1,088 1,141 1,178 1,356 1,430 1,485 6,659 6,986 7,209 2020 1,083 1,142 1,186 1,355 1,436 1,499 6,634 6,997 7,266 2021 1,084 1,149 1,199 1,352 1,439 1,507 6,616 7,012 7,318 2022 1,084 1,154 1,209 1,345 1,438 1,510 6,611 7,036 7,369 2023 1,082 1,157 1,214 1,339 1,438 1,512 6,600 7,056 7,405 2024 1,079 1,158 1,218 1,340 1,444 1,521 6,589 7,072 7,437 2025 1,082 1,166 1,228 1,340 1,448 1,528 6,580 7,090 7,469 2026 1,083 1,171 1,235 1,339 1,452 1,535 6,577 7,112 7,503 2027 1,084 1,176 1,243 1,335 1,454 1,539 6,575 7,134 7,539 2028 1,083 1,179 1,249 1,336 1,459 1,548 6,574 7,158 7,579

Average Annual Growth Rate %

2014-2028 -0.3

0.3 0.7 -0.4 0.1 0.5 -0.3

0.2 0.6

67

KENTUCKY POWER



Range of Forecasts

Internal Energy Requirements

Winter Peak Demand

68

KENTUCKY POWER




Low, Base and High Case for Forecasted Seasonal Peak Demands and Internal Energy Requirements

2012-2026

Excluding EE Adjustments

Year

Summer Peak Internal Demands (MW)

Winter (Following) Peak Internal Demands (MW)

Internal Energy Requirements (GWH)

Low Case

Base Case

High Case

Low Case

Base Case

High Case

Low Case

Base Case

High Case

2014 1,128 1,137 1,141 1,431 1,443 1,448 6,945 7,004 7,030 2015 1,123 1,140 1,145 1,423 1,444 1,450 6,911 7,014 7,045 2016 1,115 1,143 1,153 1,412 1,447 1,460 6,873 7,043 7,106 2017 1,109 1,147 1,166 1,401 1,448 1,473 6,825 7,056 7,177 2018 1,104 1,150 1,178 1,392 1,449 1,485 6,786 7,066 7,239 2019 1,100 1,153 1,190 1,384 1,451 1,497 6,750 7,077 7,301 2020 1,096 1,155 1,199 1,376 1,450 1,505 6,728 7,092 7,360 2021 1,097 1,162 1,212 1,376 1,457 1,519 6,712 7,108 7,414 2022 1,098 1,167 1,222 1,373 1,460 1,528 6,708 7,133 7,466 2023 1,096 1,170 1,228 1,367 1,460 1,531 6,697 7,154 7,502 2024 1,093 1,172 1,232 1,360 1,459 1,533 6,686 7,169 7,534 2025 1,096 1,179 1,242 1,362 1,465 1,543 6,677 7,187 7,566 2026 1,097 1,185 1,249 1,361 1,470 1,549 6,674 7,209 7,601 2027 1,098 1,190 1,257 1,360 1,474 1,556 6,672 7,231 7,637 2028 1,097 1,193 1,262 1,356 1,475 1,560 6,671 7,255 7,676

Average Annual Growth Rate %

2012-2026 -0.2

0.3 0.7 -0.4 0.2 0.5 -0.3

0.3 0.6

69

KENTUCKY ER



Total Internal Energy Requirements Comparison of 2009 and 2013 Forecasts


Forecast Year

2013 Forecast

2009 Forecast

Change From 2009 Forecast

GWH GWH GWH Percent

2009 7,963 2010 8,144 2011 8,286 2012 8,354 2013 8,417 - 2014 6,958 8,472 -1,513 -17.9 2015 6,953 8,530 -1,577 -18.5 2016 6,970 8,593 -1,622 -18.9 2017 6,975 8,651 -1,675 -19.4 2018 6,979 8,707 -1,729 -19.9 2019 6,986 8,762 -1,776 -20.3 2020 6,997 8,816 -1,819 -20.6 2021 7,012 8,874 -1,863 -21.0 2022 7,036 8,940 -1,904 -21.3 2023 7,056 9,007 -1,950 -21.7

2014-2023 Growth Rate (%) 0.2 0.7

70

2009 Fcst Actual

KENTUCKY m'm POWER


Exhibit 2-17 Kentucky Power Company Comparison of Forecasts

Internal Energy Requirements

10,000 --

9,000

8,000

7,000

1,000

5,000

4,000

3,000

2,000 2003

2007

2011

2015

2019

2023

4009 Fcst k

N$C, Actual

*ma= OmmusamaG. o

2013 Fcst

1999

2003

2007

2011

2015

2019

2023

1999

Winter Peak Demand

1,900

1,700

1,500

1,300

1,100

900

700

500

71

KENTUCKY ER


Summer Peak 2013

Forecast 2009

Forecast Change From 2009 Forecast

MW MW MW Percent

1,308 1,338 1,357 1,364 1,379 -

1,132 1,389 -258 -18.5 1,133 1,400 -267 -191 1,134 1,408 -274 -19.5 1,137 1,420 -283 -20.0 1,139 1,431 -292 -20.4 1,141 1,441 -300 -20.8 1,142 1,448 -305 -21.1 1,149 1,462 -313 -21.4 1,154 1,474 -320 -21.7 1,157 1,483 -327 -22.0

0.2 0.7



Summer and Winter Following Peak Internal Demands Comparison of 2009 and 2013 Forecasts


Forecast Year

Winter Following Peak 2013

Forecast 2009

Forecast Change From 2009 Forecast

MW MW MW Percent

2009 1,639 2010 1,668 2011 1,672 2012 1,689 2013 1,700 - 2014 1,431 1,711 -280 -16.4 2015 1,432 1,717 -285 -16.6 2016 1,431 1,728 -297 -17.2 2017 1,431 1,739 -308 -17.7 2018 1,432 1,750 -318 -18.1 2019 1,430 1,754 -324 -18.5 2020 1,436 1,771 -335 -18.9 2021 1,439 1,784 -345 -19.3 2022 1,438 1,791 -353 -19.7 2023 1,438 1,799 -361 -20.1

2014-2023 Growth Rate (%) 0.1 0.6

72

r.j_l KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan


Average Annual Number of Customers by Class 2008-2012

2008 2009 2010 2011 2012 A. Residential

1. Heating Customers 84,501 85,124 85,499 85,541 85,570 2. Nonheating Customers 59,605 58,505 57,472 56,319 55,359 3. Total 144,105 143,628 142,971 141,860 140,929

B. Commercial 29,729 29,554 29,790 29,964 30,059

C. Industrial

1. Manufacturing 963 979 977 961 954 2. Mine Power 469 459 448 445 415 3. Total 1,433 1,438 1,425 1,406 1,368

D. Other Ultimate Sales

1. Street Lighting 379 373 391 411 401 2. Other 0 0 0 0 0 3. Total 379 373 391 411 401

E. Total Ultimate Sales 175,646 174,993 174,578 173,642 172,757

F. Internal Sales for Resale

1. Municipals 2 2 2 2 2 2. Other 0 0 0 0 0 3. Total 2 2 2 2 2

G. Total Internal Sales 175,648 174,995 174,580 173,644 172,759

73

KENTUCKY "1 POWER



Annual Internal Load by Class (GWH) 2008-2012

2008 2009 2010 2011 2012 A. Residential

1. Heating Customers 1,682 1,650 1,786 1,601 1,526 2. Nonheating Customers 799 776 828 741 715 3. Total 2,481 2,426 2,614 2,342 2,241

B. Commercial 1,429 1,426 1,469 1,381 1,350

C. Industrial

1. Manufacturing 2,262 2,202 2,276 2,293 2,289 2. Mine Power 1,059 1,005 980 956 771 3. Total 3,322 3,206 3,256 3,250 3,060

D. Other Ultimate Sales

1. Street Lighting 10 10 10 11 11 2. Other 0 0 0 0 0 3. Total 10 10 10 11 11


F. Internal Sales for Resale

1. Municipals 100 94 101 94 94 2. Other 0 0 0 0 0 3. Total 100 94 101 94 94


H. Losses 568 395 474 470 400

I. Total Internal Load 7,910 7,557 7,924 7,548 7,155


Wholesale Customers Coincident Seasonal Demand (MW) and Annual Energy (MWh)

2008-2012

Summer Winter Following Coincident Demand Coincident Demand Energy

Year Vanceburg Olive Hill Vanceburg Olive Hill Vanceburg Olive Hill

2008 12.0 4.9 16.0 7.1 71,822.6 29,835.6 2009 10.5 4.9 13.8 6.0 66,257.5 29,012.4 2010 13.6 5.5 14.8 7.1 73,119.1 29,967.4 2011 12.8 5.5 12.4 5.4 67,586.4 28,021.9

2012 13.5 5.3 13.6 5.9 69,396.6 26,127.7

74

KENTUCKY ER



Recorded and Weather-Normalized Peak Load (MW) and Energy (GWH) 2008-2012

2008 2009 2010 2011 2012 Kentucky Power Company

A. Peak Load -Summer 1. Recorded 1,249 1,163 1,310 1,240 1,183 2. Weather-Normalized 1,192 1,189 1,262 1,229 1,105

B. Peak Load - Winter 1. Recorded 1,674 1,543 1,596 1,378 1,409 2. Weather-Normalized 1,534 1,524 1,413 1,468 1,432

C. Energy 1. Recorded 7,910 7,557 7,924 7,548 7,155 2. Weather-Normalized 7,874 7,610 7,728 7,595 7,290


Normalized Annual Internal Sales by Class (GWH) 2008-2012

2008 2009 2010 2011 2012

A. Residential 2,460 2,453 2,501 2,369 2,315

B. Commercial 1,429 1,438 1,439 1,387 1,364

C. Industrial 3,322 3,206 3,256 3,250 3,060

D. Other Ultimate Sales 10 10 10 11 11


F. Internal Sales for Resale 100 94 100 94 95


75

, \ A

= KENTUCKY POWER' A unit of American Electric Power 2013 Integrated Resource Plan


Profiles of Monthly Peak Internal Demands 2007 and 2012 (Actual)

2022 and 2027

1,900

1,700

1,500

1,300

E 1,100

900

700

500 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

--t■ 2007 • 2012 —i 2022 ■11(k■ 2027

76

KENTUCKY POWER


Exhibit 2-25 KENTUCKY POWER COMPANY LOAD FORECAST

DATA SOURCES OUTSIDE THE COMPANY

DATA SERIES FREQUENCY GEOGRAPHIC INTERVAL SOURCE ADJUSTMENT Average Daily Temperatures at time of Daily Peak Load

Daily Selected weather stations throughout the AEP System

1982-2012 NOAA (1) None

Heating and Cooling Degree-Days Monthly Selected weather stations throughout the AEP System

1/82-02/13 NOAA (1) Annual Sums used in long-term models

FRB Production Index, Manufacturing Monthly U. S. 1984:1-2012:12 2013:1-2042:12

BOG/FRB (3) Moody's Analytics (2)

None

None Implicit GDP Price Deflator Monthly U. S. 1984:1-2012:12

2013:1-2042:12 Moody's Analytics (2)

None

Kentucky Natural Gas Prices by Sector Monthly U. S. 1973-2012:12 DOE/EIA (4) None U.S. Natural Gas Prices Forecast by Sector Annually U. S. 2010-2035 DOE/EIA (5) None U. S. Coal Production and Consumption Annually U. S. 1975-2030 DOE/EIA (5) None Eastern Kentucky Coal Production Monthly Eastem Kentucky DOE Region 1991-2012 DOE/EIA None Employment (Total and Selected Sectors), Gross Regional Product, Personal Income and Population

Montly Selected Kentucky Counties 1980-2042 Moody's Analytics (2)

None

Source Citations: (1) "Local Climatological Data," National Oceanographic and Atmospheric Administration. (2) December 2013 Forecast, Moody's Analytics. (3) Board of Governors of Federal Reserve System, "Federal Reserve Statistical Release," 1984-2012 (4) U. S. Department of Energy/Energy Information Administration "Natural Gas Monthly", Selected Issues. (5) U. S. Department of Energy/Energy Information Administration "2013 Annual Energy Outlook" and "Weekly and Monthly Coal Production," Selected Issues.

77


Exhibit 2-26 Kentucky Power Company Residential Energy Sales

2009-2012 Actual vs. 2009 IRP

Residential Energy Sales -GWH 2009 GWH

Year Actual Forecast Difference Difference

2009 2,426 2,492 -67 -2.7 2010 2,614 2,466 147 6.0 2011 2,342 2,449 -107 -4.4 2012 2,241 2,438 -197 -8.1

Weather 2009 GWH Year Normalized Forecast Difference Difference

2009 2,453 2,492 -39 -1.6 2010 2,501 2,466 35 1.4 2011 2,369 2,449 -80 -3.3 2012 2,315 2,438 -124 -5.1


78

KENTUCKY POWER


Exhibit 2-27 Kentucky Power Company Seasonal Peak Demands

2009-2012 Actual vs. 2009 Forecast

Summer Peak Demand - MW Winter Peak Demand - MW

Summer

2009 2010 2011 2012

Summer

Actual

1,163 1,310 1,240 1,183

Weather Normalized

2009 Forecast

1,308 1,338 1,357 1,364

2009 Forecast

MW Difference

-145 -28

-117 -181

MW Difference

% Difference

-11.1 -2.1 -8.6

-13.3

% Difference

Winter

2009/10 2010/11 2011/12 2012/13

Winter

Actual

1,543 1,596 1,378 1,409

Weather Normalized

2009 Forecast

1,639 1,668 1,672 1,689

2009 Forecast

MW Difference

-96 -72

-294 -280

MW Difference

%

Difference

-5.9 -4.3

-17.6 -16.6

% Difference

2009 1,189 1,308 -120 -9.1 2009/10 1,524 1,639 -115 -7.0 2010 1,262 1,338 -76 -5.7 2010/11 1,413 1,668 -254 -15.2 2011 1,229 1,357 -127 -9.4 2011/12 1,468 1,672 -204 -12.2 2012 1,105 1,364 -259 -19.0 2012/13 1,432 1,689 -257 -15.2

79

KENTUCKY POWER


3.0 DEMAND-SIDE MANAGEMENT PROGRAMS

80

2000 2010 2011 2017

o0ral0 cu is Pt ugt rr C LiOairm r 51.1`.1 NE Yt,r Sd•

KENTUCKY ER


3.1 Kentucky Power Demand Reduction and Energy Efficiency Programs

3.1.1 Changing Conditions

(807 KAR 5:058 Sec. 6)

Since the last IRP, Kentucky Power has markedly increased the size of its DSM

programs. Spending has effectively tripled while claimed energy savings, as measured by

"first year" energy savings, have quadrupled. However, as evidenced by Figure 2, the

increases have come primarily from lighting programs.

Figure 2: DSM Programs Costs and Savings

This succcess may not be readily duplicated in future periods due to the full

phase-in of lighting standards that began in 2010. EISA 2007 requires that screw-in

lighting be 25% more efficient than traditional incandescent lights by the end of 2013

which has resulted in the typical 100, 75, 60 and 40 watt incandescent light bulbs being

phased out. CFL bulbs, as part of an EE program, may still represent savings over the

increased standard, as there are some substitutes, notably, efficient halogens. However,

by year-end 2019, the standard increases to preclude any substitutes, and the CFL bulb

becomes the de facto standard. Similarly, the commercial T-12 light has been prohibited

from manufacture or import since mid-2012. Replacing T-12 lights with T-8 lights has

constituted the bulk of commercial lighting programs nationwide but eventually, as old

stock is consumed, will no longer be considered as an option for utility lighting

81

10,000,000 -

1,000,000

100,000

10,000 -

1,000

A —A-

A 112 = 0.8818

AR' = 0.5146 100

• Xcel Minn (2011) a ida11912on)

Xcel Residential (2011)

1 , _

1 10 100 1,000 10,000 100,000 1,000,000 Measure Cost (5)/Participant

• 10

KENTUCKY mm• POWER


programs. The long-term load forecast recognizes this and assumes lighting will be at the

mandated standards. This makes any capacity savings associated with traditional lighting

programs short-lived, as they become implicit in the load forecast.

As a result, the programs that have constituted the foremost basis of utility EE

programs nationwide, namely residential and commercial lighting programs, have, and

will continue to have absent any new market transforming technologies, diminished

basis, effectiveness, and impact. While that eventuality was not wholly unforeseen, viable

substitute programs that have the same "bang-for-the-buck" and resultant popularity with

consumers have not materialized. More generally, the single biggest hurdle to

participation is the cost of the measure. Figure 3 shows this relationship for two separate

utilities for which data were available. The lower cost programs consist primarily of

lighting and other high bang-for-the-buck, low-cost measures. A similarly inexpensive,

highly cost-effective technology has yet to emerge.

Figure 3: Participation in EE Programs Relationship to Measure Cost

82

KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

3.1.2 Existing Programs

(807 KAR 5:058 Sec. 7.2.g)

Kentucky Power has offered a variety of DR and EE programs designed to

encourage customers to use electricity efficiently, conserve energy and utilize cost-

effective electrotechnologies. These include a series of information, education, and

technical assistance, as well as financial incentive programs for our residential, and

commercial customers.

Existing EE programs include those that have been filed with and approved by the

Commission. These programs are as follows:

1. Targeted Energy Efficiency Program

2. High Efficiency Heat Pump-Mobile Home Program

3. Mobile Home New Construction Program

4. Modified Energy Fitness Program

5. High Efficiency Heat Pump Program

6. Energy Education for Students Program

7. Community Outreach Compact Fluorescent Lighting (CFL) Program

8. Residential HVAC Diagnostic and Tune-up

9. Residential Efficient Products

10. Small Commercial HVAC Diagnostic Tune-up

11. Small Commercial High Efficiency Heat Pumpm/Air Conditioner

12. Commercial Incentive

The effects of current programs are embedded in the load forecast as described in

Chapter 2. The Company and the Kentucky Power DSM Collaborative (which was

established in November 1994 to develop Kentucky Power's DSM plans) have developed

DSM programs which are implemented as effectively and efficiently as possible to help

Kentucky customers save energy. Both past and present programs are described in the

Kentucky Power DSM Status Report 2012, filed with the Commission on April 5, 2013.

3.2 DSM Goals and Objectives

Today's DSM programs continue to encourage the wise and prudent use of

electricity, stressing activities that are cost-effective, promote efficiency, conserve, and

83

KENTUCKY ""■• POWER



alter consumption patterns. These programs are intended to benefit the consumer and

conserve natural resources. The specific objectives of the Company's DSM activities:

• Promoting energy conservation to customers;

• Reducing future peak demands;

• Continuing efforts and cost-effective programs designed to provide the best

possible service to customers;

• Promoting electric applications that improve system load factor;

• Striving for retention of existing customers;

• Encouraging new off-peak electrical applications; and

• Providing guidance and assistance to customers facing equipment replacement

decisions.

To be effective, programs have been designed to meet local and regional needs

and customer characteristics.

3.3 Customer & Market Research Programs

Successful demand-side management programs require a thorough understanding

of customer electrical usage characteristics, appliance ownership, conservation activities,

demographic characteristics, opinions and attitudes, and, perhaps most importantly,

customers' needs for electric service. An understanding of these factors helps in the

identification of load modifications, which may be advantageous to both the customer

and the Company; permits an assessment of their potential impact; and helps in the

development of programs to solicit customer participation. The Company utilizes data

from the Company's load research studies, customer surveys, customer billing database

and specific program-related market research to obtain this information.

Load research and customer billing data are one resource utilized to determine the

specific customer and/or end-use demand and energy usage characteristics for DSM

program evaluation. End-Use load research metering information, for example,

associated with the evaluation of DSM programs on appliances such as heat pump, water

heater, air conditioners, fluorescent lighting equipment, etc., can also be used, as

appropriate, for DSM program evaluations.

84

ENTUCKY ER


The market research activities implemented by Kentucky Power have included

DSM market/process evaluation studies. These studies focused on assessing participant

satisfaction with the various measures included in each DSM program, assisting in

determining the impact on demand by persistence and by the number of free riders,

assessing the effectiveness of the program's delivery mechanisms, assisting in

determining additional program/product benefits, and gaining insight into market

potential.

3.4 DSM Program Screening & Evaluation Process

(807 KAR 5:058 Sec. 8.2.b.)

3.4A Overview

The process for evaluating DSM impacts for Kentucky Power is practically

divided into two spheres, "existing programs" and "future impacts." Existing programs,

those programs that are well defined, follow a time-worn process for screening and

ultimate approval as explained below. Their impacts are propagated throughout the load

forecast. Future impacts, less defined, are developed with a dynamic modeling process

using generic cost and impact data. This is described in Section 3.5.

In the case of Kentucky Power, the DSM Collaborative has been responsible for

performing the function of DSM program screening and evaluation for Kentucky Power.

The Collaborative, whose initial members represented residential, commercial, and

industrial customers, was established to develop Kentucky Power's DSM plans,

including program designs, budgets and cost-recovery mechanisms. The residential and

commercial members of the Collaborative continue to review the Kentucky Power DSM

programs and modify them as appropriate.

For Kentucky Power, the evaluation process considers the DSM program's cost-

effectiveness from all perspectives and incorporates cost-recovery mechanisms. In this

regard, the Collaborative decides which DSM programs are to be screened for potential

implementation in Kentucky Power's service territory.

Through a continual monitoring process, the Company has utilized a vast amount

of data collected from each of the DSM programs to appropriately re-design and re-

85

► KENTUCKY ER


evaluate the programs so as to improve their cost-effectiveness and better target

customers for the programs. Data obtained from load research, customer billing,

customer surveys and market research have all been collected from the various DSM

programs, and detailed load impacts have been estimated from the information acquired

in the field. The Company has provided DSM Status Reports to the Commission semi-

annually since the start of program implementation in 1996, furnishing information on

program participation levels, costs and estimated load impacts. Additionally, seven

Kentucky Power DSM Evaluation Reports were submitted to the Commission, on August

15, 1997, August 16, 1999, August 14, 2002, August 15, 2005 and August 25, 2008,

August 15, 2011 and August 15, 2012, respectively. These reports provided extensive

results of the screening and evaluation of each of the DSM programs implemented.

3.4.2 Existing Program Screening Process

The DSM screening process used by Kentucky Power involved a cost-benefit

analysis for each of the DSM programs with recommendation for extension of operation

based on prospective cost performance. This included application of the Total Resource

Cost (TRC) and Ratepayer Impact Measure (RIM) tests, as well as the Utility Cost Test

(UCT) and the Participant Cost Test (PCT), as defined in the California Standard Practice

Manual. In this connection, the evaluation of the cost-effectiveness of a given DSM

program involves the determination of the net present worth of the program's benefits

and costs over the study period, which normally includes a retrospective analysis of the

previous two year program operation. Under the TRC test, such benefits and costs are

viewed from the combined perspective of all rate-payers, whereas under the RIM test, the

benefits and costs are viewed from the perspective of the non-participant, and is

synonymously referred to as the "non-participant test." The benefits and costs under the

UCT test are viewed from the perspective of the utility, and under the Participant test,

from the perspective of the program participant.

The major supply-side benefits used in the cost-benefit analysis of DSM programs

are avoided energy (production) costs and avoided demand/capacity costs (for

generation, transmission and distribution). These costs are valued on a marginal WWII

86

KENTUCKY mimm, POWER



and/or $/kW basis, as appropriate. A detailed approach (peak and off-peak periods, by

season) was used to develop avoided production costs. Marginal production costs at peak

and off-peak periods in the summer and winter seasons were applied to the appropriate

DSM program impacts. The marginal production costs were estimated year-by-year for

the forecast period based on a production cost computer model.

The benefits, costs and load impacts estimated in the cost-benefit analysis reflect

the assumptions regarding replacement and persistence of each measure within the DSM

programs over the study period. Also, the analysis considered the benefits from SO)

emission credits, NOx market price, estimates for CO? costs based on expected

legislation, and expected additional system sales, thereby improving the cost-

effectiveness of each DSM measure.

3.5 Evaluating DR/EE Impacts for Future Periods

(807 KAR 5:058 Sec. 8.2.b.)

3.5.1 Assessment of Achievable Potential

The amount of EE and Demand Response that are available are typically

described in three groups: technical potential, economic potential, and achievable

potential. Briefly, the technical potential encompasses all known efficiency

improvements that are possible, regardless of cost, and thus, cost-effectiveness. The

logical subset of this pool is the economic potential. Most commonly, the TRC test is

used to define economic potential. This compares the avoided cost savings achieved over

the life of a measure/program with its cost to implement it, regardless of who paid for it.

The third set of efficiency assets, and the one of greatest practical value, is that which is

achievable.

Of the total potential, only a fraction is achievable and only then over time. Why

all economic measures are not adopted by rational consumers speaks to the existence of

"market barriers." Barriers such as lack of access to capital and lack of information are

addressed with utility-based EE and DR programs. How much effort and money is

deployed towards removing or lowering the barriers is a policy decision made state by

state.

87

KENTUCKY mi•• POWER


3.5.1.1 Consumer Programs

EE measures save money for customers billed on a "per kilowatt-hour" usage

basis. The trade-off is reduced volumetric utility charges on the customer bill for any

conservation created through either behavioral change, more efficient consumption, or

any up-front investment in a building/appliance/equipment modification, upgrade, or any

new technology that produces a change in the utility load shape through its deployment.

On the participatory side, if the consumer feels that the new technology is a viable

substitute and will pay back in the form of reduced bills over an acceptable period of

time, the consumer will adopt, accept, or undertake it.

EE measures include efficient lighting, weatherization, efficient pumps and

motors, efficient HVAC infrastructure, and efficient appliances. Often, multiple measures

are bundled into a single program that might be offered to either residential or

commercial/industrial customers in order to deliver these products in a cost-effective

manner.

Efficiency measures will, in all cases, reduce the amount of energy consumed, but

some measures may have limited effectiveness at the time of peak demand. EE is viewed

as a readily deployable, relatively low cost, and clean energy resource that provides many

benefits. According to a March 2007 DOE study, such benefits include:

Economics

Reduced energy intensity provides competitive advantage and frees economic resources for investment in non-energy goods and services

Environment Saving energy reduces air pollution, the degradation of natural resources, risks to public health and global climate change

Infrastructure Lower demand lessens constraints and congestion on the electric transmission and distribution systems

Security EE can lessen our vulnerability to events that cut off energy supplies

Unlike supply-side resources, demand-side resources, particularly EE resources,

require consumers achieve reduced consumption. While an analysis may indicate that an

"investment" in a particular measure is cost-effective, it does not guarantee that

conservation will be universally achieved or adopted as technology adoption can be

88

- 0.0476

•

octet business

- 0:0001 --

10000,000

1,f/00,000

100000

103

011 101% 70% 0t7A 40% 00% Incentive as Percentage of Measure Cos

70% 80%

89

R - 01.97

;a47 KENTUCKY ER



dependent upon many other factors as well, including ease of adoption, market delivery

methods, market barriers, and customer economics.

Market barriers to efficiency exist which limit the rate and ultimate level at which

efficiency measures are adopted by consumers (program participants). These typically

include: high initial cost, uncertainty about performance, and "agency" problems, where

the person buying an appliance may not benefit from the improved efficiency.

To overcome many of the participant barriers noted above, a portfolio of

programs may often include several of the following elements:

• Consumer education

• Technical training

• Energy audits

• Rebates and discounts for efficient appliances, equipment and buildings

• Industrial process improvements

The level of incentives (rebates or discounts) offered to participants is a major

determinant in the pace of market transformation and measure adoption. To achieve rapid

adoption of efficiency measures, it is reasonable to expect increased program costs

associated with higher consumer incentives, higher administrative costs and marketing.

However, this relationship is not as strong (Figure 4) as the prior relationship of measure

cost to participation, as shown by the same data.

Figure 4: Relationship of Incentive Percentage to Participation

IT KENTUCKY POWER



Thus, it is safe to say that the over-riding factor affecting participation and "first

year" program savings/achievement is the availability of inexpensive energy saving

measures. Until the next breakthrough in this area emerges, it is unrealistic to expect

program achievement that aligns with mandates conceived during a period where

relatively inexpensive (lighting, primarily) programs were responsible for the bulk of the

savings.

3.5.1.2 Smart Meters

"Smart meters" are meters that receive and transmit information about energy

consumption that is available not only to the utility, but also the consumer. Enhanced

information, such as rates that vary with the time of day is enabled with a smart meter.

The promise of a smart meter is with the information in the hands of the individual

customers; they are better positioned to make decisions to reduce consumption at time of

peak.

3.5.1.3 Demand Response

Peak demand, measured in megawatts (MW), can be thought of as the amount of

power used at the time of maximum power usage. In the PJM zone, this maximum

(System peak) is likely to occur on the hottest summer weekday of the year, in the late

afternoon. This happens as a result of the near-simultaneous use of air conditioning by

the majority of customers, as well as the normal use of other appliances and (industrial)

machinery. At all other times during the day, and throughout the year, the use of power is

less.

As peak demand grows with the economy and population, new capacity must

ultimately be built. To defer construction of new power plants, the amount of power

consumed at the peak must be reduced. In addition to "passive" or "non-dispatchable"

resources like EE and VVO, "active" or "dispatchable" resources, which have impacts

primarily only at times of peak demand, include:

® Interruptible loads. This refers to a contractual agreement between the utility

and a large consumer of power, typically an industrial customer. In return for

reduced energy costs, an industrial customer agrees to "interrupt" or reduce

90

ii-r4 I; KENTUCKY ER


power consumption during peak periods, freeing up that capacity for use by

other consumers.

Direct load control. Very much like an (industrial) interruptible load, but

accomplished with many more, smaller, individual loads. Commercial and

residential customers, in exchange for monthly credits or payments, allow the

energy manager to deactivate or cycle discrete appliances, typically air

conditioners, hot water heaters, lighting banks, or pool pumps during periods

of peak demand. These power interruptions can be accomplished through

various media such as FM-radio signals that activate switches, or through a

digital "smart" meter that allows activation of thermostats and other control

devices. Often, these smaller loads can be aggregated by curtailment service

providers (CSP) so that they meet RTO minimum requirements.

® Time-differentiated rates. Offers customers different rates for power at

different times during the year and even the day. During periods of peak

demand, power would be relatively more expensive, encouraging

conservation. Rates can be split into as few as two rates (peak and off-peak)

and to as often as 15-minute increments known as "real-time pricing."

Accomplishing real-time pricing would typically require digital (smart)

metering to "download" pricing signals from a utility host system.

On a broad scale, direct load control-type programs are typically more expensive

as similar infrastructure is needed to achieve smaller load reductions. Moreover, these

programs can also introduce consumer dissatisfaction since the "economic choice" is

removed from the customer.

The following section seeks to quantify the potential for demand response in

Kentucky's service territory should the need arise.

Potential demand response resources are limited to commercial or industrial

demand response. To determine a reasonably achievable level, demand response

participants in Kentucky Power affiliate companies were surveyed to determine their

91

Iilk KENTUCKY POWER


industry and the percentage of their load that they committed, on average, to PJM.

Translating these same relationships to Kentucky Power yield the following potential by

industry (Table 8). There may be circumstances that limit the utility of this simple

extrapolation, and it is unknown whether these customers would participate. Given

Kentucky Power's current and expected capacity position within PJM, it is not necessary

to aggressively pursue all available demand response at this time.

Table 8: DR Potential

MW Industry 24 Mining 12 Chemicals 19 Refining 36 Primary Metals 1 Telecommunications 2 Electric, Gas, Sanitary Services 3 Hospitals 1 Other

97

3.5.1.4 Volt VAR Optimization (VVO)

VVO is a smart grid technology that falls under the gridSMART® umbrella of

programs. VVO provides all of the benefits of power factor correction, voltage

optimization, and condition-based maintenance in a single, optimized package. In

addition, VVO enables conservation voltage reduction (CVR) on a utility's system. CVR

is a process by which the utility systematically reduces voltages in its distribution

network, resulting in a proportional reduction of load on the network. A 1% reduction in

voltage typically results in a 1% reduction in load.

As the electric infrastructure was built out in the last century, distribution systems

were designed to ensure end-users received voltages ranging from 114 to 126 volts in

accordance with national standards. Most utility systems were designed so that customers

close to the substation received voltages close to 126 volts and customers farther from the

substation received lower voltages. This design kept line construction costs low because

voltage regulating equipment was only applied when necessary to ensure the required

minimum voltages were provided. However, since most devices operated by electricity,

92

station LTC or tap Regulator

Line Voltage Regulator

Single Phase MFR Customer

KENTUCKY POWER



especially motors, are designed to operate most efficiently at 115 volts, any "excess"

voltage is typically wasted, usually in the form of heat. Tighter voltage regulation,

enabled by smart-grid infrastructure, allows end-use devices to operate more efficiently

without any action on the part of consumers (Figure 5). Consumers will simply use less

energy to accomplish the same tasks.

Figure 5: Electric Energy Consumption Optimization

3.5.1.5 Distributed Generation (DG)

DG can take multiple forms from rooftop (or pole-mounted) solar photovoltaic

(PV) panels to combined heat and power (CHP), fuel cells, micro-turbines, diesel internal

combustion engines, and small wind turbines. From the perspective of the utility, these

different "behind-the-meter" technologies are the same in that they result in a reduction

to load and additional incremential costs to the utility to accommodate, but are owned by

the customer with a cost at a prescribed amount: either the retail net metering or PURPA

rates. Operating characteristics are different and so corresponding the "resource value" to

the utility will vary.

3.5.1.6 Technologies Considered But Not Evaluated

Some DG alternatives include: microturbines, fuel cells, CHP, and residential and

small commercial wind were not specifically evaluated. However, distributed generation

was modeled as a resource that cost either the (full retail) net metering rate or the PURPA

rate as appropriate.

Currently, these technologies cost more than other utility-scale options and were

not considered for wide-scale utility implementation. Their costs will continue to be

93

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KENTUCKY POWER


monitored. Figure 6 shows the significant variation in capital costs for DG and where the

costs are relative to other generating technologies9.

Figure 6: Distributed Generation Capital Costs

Technology (number of values)

3.5.2 Determining Expanded Programs for the IRP

Energy Efficiency

To determine the economic demand-side additions to the plan, a determination

was made as to the cost of incremental EE programs as well as the ability to expand

current programs. Figure 7 shows the make up of consumption in Kentucky Power's

Residential and Commercial sectors.

9 littp://www.nrel.gov/analysishecli_cost_dg.html

94

Kentucky Power Residential 2014 End-use

(GWh)

■ Heating

■ Cooling

■ Hot Water

■ Appliance

• Lighting

® Television

Miscellaneous

2,267 GWh Total

449 720

240

247 158 167

Kentucky Power Commercial 2014 End-use

(GWh)

■ HVAC

■ Hot Water & Cooking

■ Refrigeration

■ Lighting

■ Office

■ Miscellaneous

1,346 GWh Total

KENTUCKY POWER'

A unit alAmerican Electric Power


Figure 7: Residential and Commercial 2014 End-use in GWh

Current programs target certain end-uses in both sectors, primarily lighting.

Incremental programs can further target those areas or address other end-uses. To

determine which end-uses are targeted, in what amounts, Kentucky Power looked at

public information from one of the leading EE program administrators, Efficiency

Vermont. Efficiency Vermont provides comprehensive and fairly detailed information on

the end-uses that are impacted by a utility program as well as measure and program costs.

Kentucky Power adapted these measures to fit the climate of Kentucky. Figure 8 shows

95

100% - 0 fl

c

99% E

98%

4, 97% v,

a, 96% 0 LL

95%

a, C.) 94%

o_ 93%

KENTUCKY POWER A unit olAmerican Electric Power 2013 Integrated Resource Plan

the current program targeted end-uses as well as the end-uses that a comprehensive,

Vermont-style program would further target.

Figure 8: Current and Incremental End-use Program Target

. ,..› ep \\ef- 0

e),

\-- i'9 \>

4; ,Sebe

\ '-e>•(

c,e, s

Residential Programs

C., \'s , ,(2"(‘ ,e°ck\c'z o

ps .c,e,

sZP Business Programs

Resultant Consumption E Current Program Target E1 Incremental Program Target

What can be seen from the chart is that Kentucky Power is already targeting

residential heating, cooling and lighting measures in amounts equal to or greater than

Vermont. Incremental opportunity may lie in residential appliances and miscellaneous,

commercial refrigeration and miscellaneous, and an expansion of commercial HVAC

programs. Adoption of these programs is limited to amounts that are commensurate with

those seen in Vermont.

In the recent Mitchell Transfer Stipulation and Settlement Agreement, Kentucky

Power agreed to increase spending on cost-effective programs from the current level of

approximately $3 million annually to $4 million in 2014, $5 million in 2015, and $6

million thereafter. The Preferred Portfolio described in Chapter 4 includes program levels

in concert with that agreement.

96

1-00 1.

Utility break-even relative to RIM - value

Net metering credit in excess of PJM value; net-metered solar not economically selected

3.00

Consumer break-even under full-retail net metering 2.50

2.00

PJM Value of Solar

Net Metering Payments Utility Scale PV with ITC

® Consumer Scale PV with ITC

0.50

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

97

I1 KENTUCKY Imm POWER


VVO

Volt VAR Optimization (VVO) equipment is an additional resource that reduces

end-use consumption. This resource is available in amounts that can be reasonably

installed and tested in a given year

Demand Response

While introduction of a tariff that allows for the aggregation of smaller commercial

and industrial loads would likely result in meaningful resources becoming available, this

IRP does not add these resources due to Kentucky Power's current reserve margin. Other

options, including expanded residential DR may also be considered in the future.

Distributed Generation

DG resources were evaluated using a solar PV resource, as this is likely the

primary distributed resource. Solar also has favorable characteristics in that it produces

the majority of its energy at times when power prices in PJM are their highest. Costs

were the full net metering rate, which is the credit required by regulation. In spite of

relatively low current retail rates, customer-sited distributed generation costs the utility

more than the PJM value it provides. Figure 9 shows the dynamic in effect.

Figure 9: Solar Dynamic Effects

►,it: KENTUCKY "'''• POWER



Figure 9 demonstrates a couple of key points regarding distributed generation

generally, and distributed solar specifically. First, from the standpoint of the utility, on

the basis of revenue requirements, the full net metering retail rate exceeds the PJM value

of the capacity and energy provided, typically. Conversely, from the perspective of the

customer receiving the full retail rate, this arrangement becomes economic in the near

term. This dynamic has been the source of some controversy recently as utilities with

high exposure to distributed solar in the Desert Southwest have sought to change net

metering rules to ameliorate what amounts to a subsidy to consumers that self-generate at

the expense of those customers who do not do so.

With regard to utility-owned (or purchased) solar generation, it is expected to

become economic around 2020. This has potentially important implications for Kentucky

Power given its exposure to market energy costs, particularly if carbon costs materialize

as expected. The addition of generation that has no fuel or emissions costs may prove to

be a valuable hedge against volatile fuel and emissions costs.

3.5.5 Evaluating Incremental Demand-Side Resources

(807 KAR 5:058 Sec. 8.3.e.1.)

The Plexos® model that will be further discussed in Chapter 4 allows the user to

input demand-side EE, DR, and VVO as "resources" and model them along-side supply-

side, and all other options. Resources were constructed with the following cost profiles

(stated in "cost/first-year savings"):

98

Kentucky Power

Residential Annual GWh

Cost ($000)

Measure Life Shape

Electric Cooking 1.0 $1,156 14 Residential Other Refrigerator 2.0 $951 12 Residential Other Miscellaneous 2.0 $500 9 Residential Other

Commercial Cooling 2.0 $184 16 Commercial Cooling Refrigeration 1.0 $285 11 Commercial Other Miscellaneous 3.0 $917 10 Commercial Other

Ulig KENTUCKY ■ • POWER

A unit otAmerican Electric Power 2013 Integrated Resource Plan

Table 9: Incremental Demand-side Resources Cost Profiles

Further detail of the per participant costs is included in Table 12 of the Chapter 3 Appendix.

WO

Table 10: WO Cost Profile GWh Cost ($000) Measure Life Shape

WO 1 22.1 6,250 20 VVO W02 18.6 6,250 20 WO

Demand Response

DR resources would be assumed to be at a cost that is less than the PJM RPM

cost of capacity. This assumption is in line with how these resources are typically priced

to ensure a margin of profitability exists for curtailment service providers. However, as

previously mentioned, given the Company's current (PJM) capacity length resulting from

the Preferred Portfolio, there would be little incentive to offer such enrollment program

in the near-term.

Customer-Owned (Distributed) Solar

Customer-owned resources, generally, and solar resources, specifically were

modeled as a stream of payments valued at the full-retail rate which is consistent with

current net metering rules. This treatment is independent of assumptions of installation

and operating costs of the solar resources, as they are borne by the customer, and are not

part of revenue requirements. This is consistent with how other demand-side resources

are modeled.

99

KENTUCKY •■•• POWER



3.5.6 Optimizing the Incremental Demand-side Resources

(807 KAR 5:058 Sec. 8.3.e.3.)

The Plexos® software views demand-side resources as non-dispatchable

"generators" that produce energy similar to non-dispatchable supply-side generators such

as wind or solar. Thus, the value of each resource is impacted by the hours of the day and

time of the year that it "generates" energy. Plexos® optimized under five different

economic scenarios.

3.5.7 Expected Program Costs and Benefits

(807 KAR 5:058 Sec. 8.3e.2,4, and 5.)

Energy Efficiency

EE resources optimized in equal amounts under all five economic scenarios. The

Commercial Cooling and Commercial Refrigeration measures were selected in every

year in the forecast period beginning in 2014; adding an incremental 3 GWh of annual

energy reductions each year. The failure to select other measures in any of the scenarios

reflects the wide gulf in the relative cost-effectiveness of the measures. These additions,

in these quantities, would not constitute an expansion of programs that is in concert with

the Mitchell Stipulation and Settlement Agreement. The preferred portfolio adds

additional efficiency programs to approximate the spending targets in the agreement,

increasing the incremental efficiency resources from 3 GWh to 5 GWh in 2014 and 10

GWh by 2016 as depicted in Figure 10. That level, along with the current programs,

represents energy savings of 0.9% of residential and commercial sector consumption

annually.

100

KENTUCKY ER


Figure 10: Incremental Energy Savings Resources

12 1

^ 10

0 8 ,,,,),

u 5 o cii cc an

r cn ru,

ro 2

LL.9 tx G.) co 'N (b (%) 0 "y '1, '7., t* (0 (0 ''‘ Cb 7E.

'.1, l• 1, .1" 'I/ le 1, 1, l' l'. l' 1. '1‘ 1, 1. O>. O`' O' C>. & & & & & & & 61' &

ar

L ffl Commercial Cooling

$: Commercial Misc

Residential Refrigerator

n Commercial Refrigeration

Residential Misc

VVO

The VVO resources that are currently being installed and are expected to be

operational in 2014 were allowed to optimize in 2014 and did under all economic

scenarios. Circuits where less savings are expected optimize at different times, depending

on the economic scenario. The "blocks" of VVO consist of bundles of circuits that save

between 3-4 MWs of summer peak demand and 18-24 GWh of energy annually. Table

11 shows the schedule when VVO resources optimized under different economic

scenarios.

Table 11: WO Blocks

VVO Blocks Base Band Low Band High Band High CO2 No CO2

2014 1 1 1 1 1 2015 0 0 0 0 0 2016 0 0 0 0 0 2017 0 0 0 0 0 2018 0 0 0 0 0 2019 0 0 0 0 0 2020 0 0 0 0 0 2021 3 1 3 3 3 2022 0 2 0 0 0 2023 0 0 0 0 0 2024 0 0 0 0 0 2025 0 0 0 0 0 2026 0 0 0 0 0 2027 0 0 0 0 0 2028 0 0 0 0 0

101

f;L11' gENTUCICY ■•"' POWER


These estimates are subject to future revision as more operational information is

gained from the installation that is currently underway.

Distributed Solar

From the perspective of Kentucky Power, distributed solar resources did not

optimize under any economic scenario during the planning period as discussed in Section

3.5.2.

The estimated cost to Kentucky Power's customers to implement the expanded

programs in the Preferred Portfolio, including Distributed Solar, are included in Table 13

in the Chapter 3 Appendix.

3.5.8 Discussion and Conclusion

Incremental EE programs, above programs that are currently approved, will cost

more than current programs as non-lighting meaures are implemented in greater

proportion. Further expansion into the commercial sector may provide the more cost-

effective prospective programs incremental to the current portfolio, although, it will

likely take a more comprehensive approach, which remains cost-effective in total, to

reach the spending targets in the Mitchell Stipulation and Settlement Agreement.

The current VVO program that is underway has been validated from an economic

perspective. The model did not optimize an expansion of the program until next decade,

but that result is subject to the realization of operational and cost data that will arise from

the current program.

DG, when compensated at the full retail net metering rate, as required by current

rules, is not economical from a (utility) revenue requirements perspective. However, that

excess compensation does improve the economics from a DG consumer perspective,

making it likely Kentucky Power will see these resources being added on the system by

its customers over the time.

102

KENTUCKY ER


3.6 Issues Addressed in KPSC Staff Report

The Commission issued their Staff's report on Kentucky Power's 2009 Integrated

Resource Plan and requested that the Company address certain issues in its next IRP

report (this report). The following issues pertaining to DSM are restated from the Staff

report and addressed below:

Kentucky Power should work to increase its portfolio of DSM programs to assist in achieving demand reductions and further examine the expansion of current programs.

Kentucky Power expanded its program portfolio from seven residential programs

to twelve residential and commercial programs. Further, the Company has agreed

to increase spending on cost-effective programs to $6 million annually by 2016.

3.7 Chapter 3, Appendix - DSM Program Descriptions

(807 KAR 5:058 Sec. 7.2g. and Sec. 8.3.e.1, 3-5)

1. Targeted Energy Efficiency Program The Kentucky Power Targeted Energy Efficiency Program (TEE) provides

weatherization and EE services to qualifying residential customers who need help

reducing their energy bills. The Company provides funding for this program through the

Kentucky Community Action network of not-for-profit community action agencies. The

program funding and service is supplemental to the Weatherization Assistance Programs

offered by local community action agencies. This program provides energy saving

improvements to existing homes. Program services can include these items, as applicable

and per program guidelines:

® Energy audit

• Air infiltration diagnostic test to find air leaks

® Air leakage sealing

® Attic, floor, side-wall insulation

• Duct sealing and insulation

a High efficiency compact fluorescent light bulbs (CFLs)

a Domestic hot water heating insulation (electric)

® Customer education on home energy efficiency

a Partial funding High efficiency heat pump (restrictions apply)

103

ENTUCKY ER •


2. High Efficiency Heat Pump-Mobile Home Program

The Kentucky Power Mobile Home High Efficiency Heat Pump Program (MHHP)

offers an incentive to residential customers who live in a mobile home and upgrade their

central electric resistance heating system with a new, high efficiency heat pump unit. To

qualify, the new heat pump unit must have a minimum rating of 13 SEER (Seasonal

Energy Efficiency Ratio) and 7.7 HSPF (Heating Seasonal Performance Factor).

3. Mobile Home New Construction Program

The Kentucky Power Mobile Home New Construction Program (MHNC) offers an

incentive to residential customers who purchase a new mobile home having an insulation

upgrade and a high efficiency heat pump unit. To qualify, the new heat pump unit must

have a minimum rating of 13 SEER (Seasonal Energy Efficiency Ratio) and 7.7 HSPF

(Heating Seasonal Performance Factor).

4. Modified Energy Fitness Program

The Kentucky Power Modified Energy Fitness Program (MEF) provides

weatherization and EE services to qualifying residential customers who need help

reducing their energy bills. This program provides energy saving improvements to

existing homes. Program services can include these items, as applicable and per program

guidelines:

® Complete energy audit with customized report

()Air infiltration diagnostic test to find air leaks

*Energy savings booklet

*Energy conservation measures installed (per program guidelines)

5. High Efficiency Heat Pump Program

The Kentucky Power High Efficiency Heat Pump Program (HEHP) offers an

incentive to residential customers who upgrade their central electric resistance heating

system or existing less efficient heat pump system to a new, high efficiency heat pump

unit. To qualify, the new heat pump unit must have a minimum rating of 13 SEER

(Seasonal Energy Efficiency Ratio) and 7.7 HSPF (Heating Seasonal Performance

104

Lila KENTUCKY POWER A unit of American Electric Power 2013 Integrated Resource Plan

Factor) for resistance heat upgrade, or 14 SEER and 8.2 HSPF for upgrading from a less

efficient existing heat pump to a high efficiency heat pump unit.

6. Energy Education for Students Program

The Kentucky Power Student Energy Education Program (EEFS) targets 7th grade

students at participating schools within the Kentucky Power Company service territory.

The program introduces them to various aspects of responsible energy use and

conservation. With this program, students use math and science skills to learn how

energy is produced and used, and methods to conserve energy that can easily be applied

in their own homes.

The Company partners with the National Energy Education Development Project

(NEED) to implement this program. NEED is an established and respected energy

education organization that has been presenting programs for teachers and students in

Eastern Kentucky for many years. The program, provided at no cost to participating

school systems, includes:

• Professional development for teachers where they will receive classroom

curriculum and educational materials on energy, electricity, economics and the

environment

a Each Student receives compact fluorescent lights (CFLs) to help students apply

their classroom learning at home

® An opportunity for participating students and their families to make the ENERGY

STAR" Pledge

7. Community Outreach Compact Fluorescent Lighting (CFL) Program

Through the CFL Outreach Program, Kentucky Power distributes compact

fluorescent lights (CFLs) to customers at company-sponsored community events. The

program aims to educate and encourage customers to save money by using energy

efficient lighting. The company sponsors community distribution events throughout the

year where a package of CFLs is distributed to each qualifying residential customer.

Customer energy education is also provided at these events.

105

KENTUCICY ER


8. Residential HVAC Diagnostic and Tune-up The residential and commercial customer will be offered an incentive when receiving

this Diagnostic and Tune-up service from a participating, state licensed contractor. It will

help extend the life of the system, reduce energy costs and improve the interior comfort

of your business. The diagnostic and tune-up service includes testing for inefficiencies in

air conditioning and heat pump systems due to air-restricted indoor or outdoor coils and

over or under refrigerant charge.

9. Residential Efficient Products The Kentucky Power Residential Efficient Products Program (REP) offers residential

customers instant rebates on ENERGY STAR® lighting products at participating retail

stores across our service territory. The program targets the purchase of lighting products

through in-store promotion as well as special sales events. Customer incentives facilitate

the increased purchase of high-efficiency products while in-store signage, sales associate

training and support makes provider participation easier.

A convenient online store where you can shop for energy efficient lighting and get

immediate discounts is also available, including specialty and hard-to-find CFLs.

10. Small Commercial HVAC Diagnostic Tune-up The commercial customer will be offered an incentive when receiving this Diagnostic

and Tune-up service from a participating, state licensed contractor. It will help extend the

life of the system, reduce energy costs and improve the interior comfort of your business.

The diagnostic and tune-up service includes testing for inefficiencies in air conditioning

and heat pump systems due to air-restricted indoor or outdoor coils and over or under

refrigerant charge.

11. Small Commercial High Efficiency Heat Pump/Air Conditioner

The commercial customer will receive financial incentives for upgrading to a new

qualifying central air conditioning or heat pump system (up to a five-ton unit with a

Consortium for Energy Efficiency (CEE) Tier 1 rating). The incentive helps offset the

cost of the investment, and the improved efficiency can give long-term savings.

106

KENTUCKY ER


12. Commercial Incentive

The Kentucky Power Commercial Incentive Program (CIP) offers a convenient way

to receive funding for common EE projects. The Commercial Inventive Program provides

financial incentives to business customers who implement qualified energy-efficient

improvements and technologies.

Incentives are available for a variety of energy-saving technologies in existing

buildings and new construction projects. Choose from a menu of prescriptive measures

with standardized incentives. The program menu includes, but is not limited to,

incentives for:

Lighting

• Heating, ventilation, and air conditioning (HVAC)

® Food Service and Refrigeration

A complete list of the eligible equipment and incentive amounts can be found in

the Program Application located at KentuckyPower.com/save/programs.

107

164 KENTUCKY ER


Incremental Energy Efficiency Resource Cost Assumption Detail:

Table 12: EE Resource Costs

Program Gross MWh easure

life Incentives

participant

OS Net MWh

Net

Lifetime

MWh Admin Casts

Netta

Gros s

Adjustor Adjusted

ents for First Year /First year % Base a •s savings entive ye ar Class

Fragrant % of

5ector

A/C 13.3 16 2,160

1,794

2,069

680 35,414

2,245

3,780

t

Wil

INIZOWel 596

1,2601

166 6

2 0 1

2.006

2,006 006

2 006

2,006

as

08

1111C01 0.8

1.0

1.0

1.8

6

111.11111121 11111112111

7 8 15.8

IIIIIMINIMEMIllanunn 861

158

•

285

0.73

0- 22

WI 040

2011

11111 5

2011

2011

2011

Business

5 IMMIN-

B n

0.00%

000%

0.11%

0.2650 0 0 %

0.06%

Hat Water

55 10

960 13

158 11 MIIWIRMINEW

dustrial Process

Refrigeration

10,145

2,504 Bu n

Burne ss All Other 56 10 2,104

EDIIIIIIIIIIIIIIIIIIIIIIMIIIIIIIEEIMIIIrl 3, 444

(561

12.7

57.5 160.9

2,006

2,006

0.8

0.7 1.0 0.7

4.5 917 873

1.03 aso

2011

2011 Bus n Business

0.12%

a 67Y

Program Gross MWh

measure

life Incentives

participant

costs Net MWh

Net

Lifetime

MWh Admin Costs

Net to

Gross

Adjustor

ants for

Baseline

Adjusted

First Soar

Savings

(MIA/h)

5/First year

MWh savings incentive Year Class

Program

%of

Sector

A/C 0.1 16 30 21 0.1 1.9 161 as 2.1 az 768 0.59 2011 Residential 0.01% Cooking and Laundry 0.3 14 71 362 0.3 4.5 161 0.8 1.0 0.2 1,156 0.16 2011 Residential 0.03% lighting 2.1 7 197 33 2.5 17.1 16I 0.5 0.8 0.8 4e3 0.86 2011 Residential 0.41% Refrigeration 05 12 213 39 0.5 5.9 161 0.8 1.0 0.4 951 0.65 2011 Residential 0.05%

Space Heat 0.7 24 106 191 0.9 20.6 161 0.8 0.6 0.4 743 0.36 2011 Residential 0.01% All Other 0.6 9 98 (44) 0.6 5.8 161 0.8 1.0 0.5 500 1,81 2011 Residential 0.09%

Total 1.3 8 157 70 1.5 11.5 161 0.5 0.8 0E 545 0.69 2011 Residential 0.57%

Table 13: DSM Program Costs Estimates

Kentucky Power Demand-side Estimated Cost - Preferred Plan ($000)

Expanded

Energy

Efficiency

Approved

Energy

Efficiency

Sub-total

Energy

Efficiency VVO

Distributed

Solar (Net

Metering) Total DSM

2014 1,024 3,100 4,124 618 4,742

2015 1,996 3,162 5,158 618 5,776

2016 2,530 3,225 5,756 618 2,101 8,475

2017 2,581 3,290 5,871 618 714 7,203

2018 2,633 3,356 5,988 618 729 7,335

2019 2,685 3,423 6,108 618 743 7,469

2020 2,739 3,491 6,230 618 1,516 8,364

2021 2,794 3,561 6,355 1,086 1,547 8,988

2022 2,850 3,632 6,482 1,086 2,367 9,935

2023 2,907 3,705 6,611 1,086 2,414 10,112

2024 2,965 3,779 6,744 1,086 3,283 11,113

2025 3,024 3,854 6,879 1,086 4,186 12,151

2026 3,085 3,932 7,016 1,086 5,124 13,226

2027 3,146 4,010 7,156 1,086 6,969 15,212

2028 3,209 4,090 7,300 1,086 8,886 17,272

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4.0 RESOURCE FORECAST

(807 KAR 5:058 Sec.8.1. and Sec. 8.2.d.)

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4.1 Resource Planning Objectives

(807 KAR 5:058 Sec.8.5.a. and Sec. 8.5.c.)

The primary objective of power system planning is to assure the reliable,

adequate and economical supply of electric power and energy to the consumer, in an

environmentally compatible manner. Implicit in this primary objective are related

objectives, which include, in part: (1) maximizing the efficiency of operation of the

power supply system, and (2) encouraging the wise and efficient use of energy.

Other objectives of a resource plan include planning flexibility, creation of an

optimum asset mix, adaptability to risk and affordability. In addition, given unique

impact on generation of environmental compliance, the planning effort must be in concert

with anticipated long-term requirements as established by the environmental compliance

planning process.

4.2 Kentucky Power Resource Planning Considerations

4.2.1 General

(807 KAR 5:058 Sec.8.5.b.)

This IRP document presents a plan for Kentucky Power to meet its obligations as

a stand-alone company operating in the PJM RTO.

Under the Preferred Portfolio, developed during this planning process, Kentucky

Power is anticipated to meet its reserve margin requirements over the forecast period.

Exhibit 4-12 shows the annual capacity additions and resultant reserve margin for this

Plan.

4.2.2 Generation Reliability Criterion

(807 KAR 5:058 Sec.8.5.d.)

On October 1, 2004, the AEP System-East Zone transferred functional control of

its transmission facilities, as well as generation dispatch including the transmission and

generation facilities owned by Kentucky Power, to PJM (the Commission approved this

action by order dated September 10, 2003, in consolidated Cause Nos. 42350 and 42352).

With that, the PJM Reliability Assurance Agreement defines the requirements

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surrounding various reliability criteria, including measuring and ensuring capacity

adequacy. In that regard, each Load Serving Entity (LSE) in PJM is required to provide

an amount of capacity resources determined by PJM based on several factors, including

PJM's Installed Reserve Margin (IRM) requirement. The IRM is based on the amount of

resources needed to maintain, among other things, a loss-of-load expectation of one day

in ten years. Additionally, load diversity between each LSE and the PJM RTO zones and

generating asset equivalent forced outage rates are other factors that impact each LSE's

required minimum reserve levels.

The PJM RTO determines generation planning reserve requirements using

probabilistic methods and a target loss of load criterion of one day in ten years. The

method is similar to that historically used by Kentucky Power. PJM determines an

installed capacity margin that has to be met by each of its members. This is converted

into PJM Unforced Capacity (UCAP) requirements. However, for ease of understanding,

the requirement is expressed in this report in terms of Installed Capacity (ICAP).

Although the current plan contains a changing mix of capacity through time, it

also contains uncertainty surrounding the long-term forecast. As a result, Kentucky

Power's IRM was held steady at the current 15.6% threshold for the remainder of the

forecast period. However, it is important to note that PJM can revise the IRM annually as

required, and as a result Kentucky Power will adjust the future IRM estimates

accordingly.

In February 2007, AEPSC, as agent for the AEP System-East Zone LSEs, gave

formal notice of its intent to opt-out of the initial PJM "Reliability Pricing Model" (RPM)

capacity auction and, instead, meet its capacity resource obligation through participation

in the optional, FERC-authorized Fixed Resource Requirement (FRR) construct. FRR

requires Kentucky Power to set forth its future capacity resource plan under, essentially,

a "self-planning" format. This is an approach that would, however, initially not give

Kentucky Power access to those generating sources offered into the PJM capacity

auction, but rather would allow Kentucky Power to be free to plan for and build (or buy)

the required generating capacity that would best fit the needs of its customers - such

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capacity purchases being limited by rule to either non-PJM generation sources, or PJM

generation sources not cleared/picked-up within the RPM auction process.

Kentucky Power and the remaining two cost-based affiliates that are party to the

proposed PCA APCo and I&M—have continued to opt out of the RPM capacity

auction through the 2016/17 delivery year, for which the auction was held in May 2013

and will determine for each subsequent year whether to continue to utilize FRR for an

additional year or to opt-in to the RPM auction for a minimum five-year period. That

election for the next, 2017/18, delivery year has not yet been made.

4.2.3 Existing Pool and Bulk Power Arrangements

4.2.3.1 Interconnection Agreement

As stated in Section 1.1, on December 17, 2010, in accordance with Section 13.2

of the Pool Agreement, each of the Pool members provided notice to the other members

(and to AEPSC, as agent) to terminate the Pool Agreement (which includes the IAA), on

January 1, 2014. As a result, effective January 1, 2014, Kentucky Power will be

responsible for its own generation resources and will need to maintain an adequate level

of power supply resources to individually meet its own load requirements for capacity

and energy, including any required reserve margin.

4.2.3.2 Transmission Agreement

The AEP System Transmission Agreement, updated and approved by FERC

Order on October 29, 2010, provides for the sharing among the members of the AEP

System-East Zone, including Kentucky Power, of the costs incurred by the members for

the ownership, operation, and maintenance of their portions of the high voltage

transmission system, in order to enhance equity among the members for the continued

development of a reliable and economic high voltage system. Members having high

voltage transmission investments greater than their respective load shares receive

payments from members with investments less than their respective load shares.

4.2.3.3 PJM Membership

On October 1, 2004, the AEP System-East Zone, including Kentucky Power,

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rit;' KENTUCKY imm POWER



joined PJM. PJM is a FERC-approved RTO that coordinates the movement of wholesale

electricity in all or parts of thirteen states and the District of Columbia. PJM manages a

regional planning process for expansion of the transmission system and continuously

monitors the transmission grid. PJM operates a competitive wholesale electricity market

and dispatches the generating units of its members, based on energy offers made by the

members, seeking to provide the lowest possible cost of electricity within its footprint.

PJM sets generation planning reserve requirements for its members.

4.2.4 Environmental Compliance

(807 KAR 5:058 Sec.8.5.f)

4.2.4.1 Introduction

In support of requirements found in 807 KAR 5:058 Sec.8.5.f, the following

information provides background on both current and future environmental (including air

emissions) regulatory compliance plan issues within the Kentucky Power system. The

Company's goal is to develop a comprehensive plan that not only allows Kentucky

Power to meet the future resource needs of the Company in a reliable manner, but also to

meet increasingly stringent environmental requirements in a cost-effective manner.

4.2.4.2 Air Emissions

There are numerous air regulations that have been promulgated or that are under

development, which will apply to Kentucky Power's facilities. Currently, air emissions

from plants are regulated by Title V operating permits that incorporate the requirements

of the Clean Air Act (CAA) and the State Implementation Plan (SIP). Other applicable

requirements include those related to the Clean Air Interstate Rule (CAIR), MATS and

the New Source Review (NSR) Consent Decree. Several air regulatory programs are

under development and will apply to the Rockport and Mitchell plants, including those

related to the regulation of GI-IG and revisions to the National Ambient Air Quality

Standards (NAAQS) for SO?, NOR, fine particulate matter, and ozone.

Potential air emissions at Kentucky Power's units, including the Rockport and

Mitchell units, are reduced through the use of all or some of a combination of

electrostatic precipitators (ESP), low sulfur coal, low NO burners, over-fire air (OFA),

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KENTUCKY POWER


activated carbon injection (AC1), Wet FGD, SCR, as well as dry fly-ash handling

systems.

In past years, Kentucky Power has been a party to the IAA, Modification 1,

effective 1996. Through this agreement, Kentucky Power jointly purchased SO2

allowances procured for the AEP-East compliance. Additionally, any SO2 allowance

excesses or shortages were sold to or purchased from the other parties to the agreement if

needed.

Environmental regulations have expanded beyond those covered by the IAA. For

example, the IAA does not cover the allowance program established for emissions of

NO,. In addition, evolving environmental regulations such as the MATS Rule establish

unit-level emission requirements, rather than system-wide emission caps.. For these

reasons, on December 17, 2010, in accordance with Section 13.2 of the Pool Agreement,

each of the Pool members provided notice to the other members (and to AEPSC, as

agent) to also terminate the IAA, in addition to the Pool Agreement, on January 1, 2014.

4.2.4.3 Environmental Compliance Programs

4.2.4.3.1 Title IV Acid Rain Program

The Title IV Acid Rain Program rules were developed in response to the CAA

Amendments of 1990 and required state environmental agencies to promulgate rules

implementing the Federal program. Compliance with Title IV SO2 requirements involved

continually evaluating alternative fuel strategies, exercising opportunities to purchase

sulfur dioxide allowances, and retrofit of post-combustion technologies in order to lower

the overall cost of compliance.

The acid rain NO reduction program was also implemented using a two-phase

approach, with the first phase becoming effective in 1996 and the second phase in 2000.

Under the NO reduction program, the acid rain rules established annual NO rates that

varied depending on boiler-type. However, the rules allowed companies to comply with

the Title IV NO standards by using system-wide averaging plans. For Title IV NOx

compliance, AEP's strategy included installing low-NOx burner technologies on its

Phase II NOx units and using an averaging plan for its remaining generating units.

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4.2.4.3.2 NOx SIP Call

In addition to the Title IV NO reduction program, the NO SIP Call was designed

to reduce the interstate transport of NO emissions that were determined to significantly

impact downwind ozone concentrations. For those states opting to meet the obligations of

the NO„ SIP call through a cap and trade program, the EPA included a model NOx

Budget Trading Program rule (40 CFR 96), which was developed to facilitate cost

effective emissions reductions of NO from large stationary sources. The NO SIP Call

rules generally required EGUs to reduce NO emissions to a level roughly equivalent to a

0.15-Ib/mmBtu emission rate, applicable during the ozone season that runs from May 1st

through September 30th each year. The initial compliance deadline for the NO SIP Call

emission reductions was May 31, 2004. The SIP Call utilized an emissions allowance

system that allowed AEP and Kentucky Power to comply with the rates by the most cost-

effective method, which was either to install control technology, purchase allowances, or

a mix of both.

Planning for the NO SIP Call allowances and emissions was performed for

Kentucky Power and AEP-East utilizing the IRP process, review of emissions and control

effectiveness, allowance availability, NO market prices and proposed regulatory

changes. Projected emissions, including any future changes to the NO reduction

effectiveness, were compared to the available allowance inventory including any

potential effects of progressive flow control and projected inventory to determine the

amount of allowances that were required to ensure compliance. Flow control provisions

were included in the NO SIP Call to discourage excessive use of banked allowances in a

particular ozone season. Flow control was triggered if the total number of banked

allowances from all sources exceeded 10 percent of the region-wide NO emissions

budget. The compliance plan for Big Sandy Plant to meet this requirement included

installation of an OFA burner modification and water injection system and boiler tubes

overlay on Unit 1 and installation of a selective catalytic reduction (SCR) system on Unit

2. The latter installation also required upgrading the Unit 2 ESP. Similar NOx reduction

technologies were implemented at other units across the AEP System. Beginning in 2009

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KENTUCKY POWER



with the commencement of CAIR, the NO Budget SIP Call Program and progressive

flow control ended.

4.2.4.3.3 Clean Air Interstate Rule (CAIR)

On March 10, 2005, the EPA announced the CAIR, which called for significant

reduction of SO, and NO from EGUs. The CAIR program incorporated three cap-and-

trade programs: an ozone season NO reduction program that replaced the NO SIP Call

program, an annual NO reduction program, and an annual SO2 reduction program that

was administered through the Title IV Acid Rain Program. In order for Kentucky Power

to have maintained sufficient allowances to be compliant with the CAIR, it planned to

purchase a significant number of allowances on an annual basis.

On July 11, 2008, the District of Columbia Circuit Court of Appeals issued a

ruling vacating the CAIR and remanding the rule back to the EPA for revision. However,

on December 23, 2008, the Court indicated in a second ruling that the CAIR was being

remanded to EPA for revision and was not being vacated. Planning for compliance at this

time for CAIR was necessary, but the Company was mindful that more stringent and

restrictive emission policies would likely be the result of the revision.

EPA finalized the Cross State Air Pollution Rule (CSAPR) in 2011 to replace

CAIR and reduce the interstate transport of NO and SO2 emissions. The U.S. Court of

Appeals for the District of Columbia Circuit vacated CSAPR in August 2012 based on

the methodology used to establish emissions reductions and EPA's failure to allow states

to develop their own emission reduction plans in the first instance. On June 24, 2013, the

U.S. Supreme Court granted EPA's appeal of the D.C. Circuit decision to vacate CSAPR,

with oral arguments being heard before the Court on December 10, 2013. A decision is

not expected until 2014. CAIR requirements remain in place and no immediate action

from states or affected sources is expected.

4.2.4.3.4 MATS Rule

The final MATS Rule became effective on April 16, 2012, with compliance

required within three years of this date (with the possibility of a one-year administrative

extension in certain circumstances). This rule regulates emissions of hazardous air

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,f.,;.Lti KENTUCKY ■ •• POWER



pollutants (HAPs) from coal and oil-fired electric generating units. HAPs regulated by

this rule are: 1) mercury; 2) several non-mercury metals such as arsenic, lead, cadmium

and selenium; 3) various acid gases including hydrochloric acid (HCI); and 4) many

organic HAPs. The MATS Rule includes stringent emission rate limits for several

individual HAPs, including mercury. In addition, this rule contains alternative stringent

emission rate limits for surrogates representing two classes of HAPs, acid gases and non-

mercury particulate metal HAPs. The surrogates for the non-mercury particulate metal

and acid gas HAPs are filterable particulate matter (PM) and HCI, respectively. The rule

regulates organic HAPs through work practice standards.

AEP and Kentucky Power successfully tested and installed an active carbon injection

(ACI) system to mitigate mercury emissions at the Rockport Plant (originally to meet the

requirements of the now-vacated Clean Air Mercury Rule), and recently obtained

approval from the Indiana Utility Regulatory Commission to install a dry sorbent

injection (DSI) technology to assure compliance with the MATS requirements. The

Mitchell Plant is anticipated to meet the requirements set forth in the MATS Rule without

modification.

4.2.4.3.5 NSR Settlement

On October 9, 2007, AEP entered into a consent decree with the Department of

Justice and other parties pertaining to the interpretation of the EPA's new source review

(NSR) requirements (the "NSR Consent Decree"), with the purpose of the agreement

being to settle all complaints filed against AEP and its affiliates, including Kentucky

Power. Kentucky Power was required by the NSR Consent Decree to continuously

operate low NOx burners and burn a coal with a sulfur content no greater than 1.75

lb./mmBTU on an annual average basis as of Otober 9, 2007 for Big Sandy Unit 1, which

is consistent with the unit's previous fuel specification. Kentucky Power was also

required to continuously operate an SCR on Big Sandy Unit 2 by January 1, 2009. The

NSR Consent Decree also required Kentucky Power to retrofit Big Sandy Unit 2 with an

FGD system, or retire or repower the unit, by December 31, 2015.

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Table 14: NSR Consent Decree Annual (AEP) NO Ca

Calendar Year Annual Tonnage Limitations for NO

2009 96,000

2010 92,500

2011 92,500

2012 85,000

2013 85,000

2014 85,000

2015 75,000

2016, and each

year thereafter 72,000


The NSR Consent Decree also originally required AEP to retrofit SCR and FGD

systems on Rockport Units 1 and 2, in which Kentucky Power owns a 15% interest, by

December 31, 2017 and December 31, 2019, respectively.

Minor changes were made to the Consent Decree in 2009 and 2010 (the First and

Second Modifications) to adjust the compliance dates for APCo's Amos Units 1 and 2 to

correspond to actual outage schedules. These changes did not impact the Big Sandy or

Rockport Plants.

On February 22, 2013, AEP, along with the DOJ, EPA, and other parties, filed a

proposed Third Modification to the Consent Decree in the United States District Court

for the Southern District of Ohio, Eastern Division. This Modification to the NSR

Consent Decree allows AEP to install DSI on both units at Rockport Plant by April 16,

2015, and defer the installation of high efficiency scrubbers on Units 1 and 2 until

December 31, 2025 and December 31, 2028, respectively.

The Third Modification to the Consent Decree also contains revised annual NO

and SO2 caps for the AEP operated coal units for AEP-East, of which Kentucky Power is

a part. These annual caps are displayed in Tables 14 and 15.

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ENIUCEW VIER


Table 15: Third Modification to the Consent Decree Annual (AEP) SO2 Cap

Calendar Year Annual Tonnage Limitations for SO2

2016 145,000

2017 145,000

2018 145,000

2019-2021 113,000

2022-2025 110,000

2026-2028 102,000

2029, and each


The Modified Consent Decree also established annual tonnage limits for SO2 for

the Rockport Plant. These annual caps—applicable to the full (100%)-plant are displayed

in Tabe 16.

Table 16: Third Modification to the Consent Decree Annual SO2 Cap for Rockport Plant

Calendar Year Annual Tonnage Limitations for SO2

2016 28,000

2017 28,000

2018 26,000

2019 26,000

2020-2025 22,000

2026-2028 18,000

2029, and each


4.2.4.4 Future Environmental Rules

Several environmental regulations have been proposed that will apply to the

electricity generating sector once finalized. The following is not meant to be

comprehensive, but lists some of the major issues that will need to be addressed over the

forecast period.

4.2.4.4.1 Coal Combustion Residuals (CCR) Rule

The EPA issued a proposed rule in June 2010 to address the management of

residual byproducts from the combustion of coal in power plants (coal ash) and captured

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KENTUCKY PO ER A unit otAmerican Electric Power


by emission control technologies, such as FGD. The proposed rule includes specific

design and monitoring standards for new and existing landfills and surface

impoundments, as well as measures to ensure and maintain the structural integrity of

surface impoundment/ponds. The proposed CCR rulemaking would require the

conversion of most "wet" ash impoundments to "dry" ash landfills, the relining or closing

of any remaining ash impoundment ponds, and the construction of additional waste water

treatment facilities by approximately January 1, 2018. Kentucky Power anticipates that

the CCR Rule—based on the preliminary assumption that these residual materials may be

categorized as "Subtitle D," or non-hazardous materials—would require plant

modifications and capital expenditures (which are factored into this IRP) to address

these requirements by, approximately, the 2018 timeframe. The final rule is expected in

2014.

4.2.4.4.2 Effluent Limitation Guidelines and Standards (ELG)

The EPA proposed an update to the ELG for the steam electric power generating

category in the Federal Register on June 7, 2013. The ELG would require more stringent

controls on certain discharges from certain EGUs and will set technology-based limits for

waste water discharges from power plants with a main focus on process and wastewater

from FGD, fly ash sluice water, bottom ash sluice water and landfill/pond leachate.

Kenrucky Power anticipates that wastewater treatment projects will be necessary at the

Rockport and Mitchell units and these have been considered as part of the respective

long-term unit evaluations. The final rule is expected in 2014.

4.2.4.4.3 Clean Water Act "316(b)" Rule

A proposed rule for the Clean Water Act 316(b) was issued by the EPA on March

28, 2011, and final rulemaking is expected in early 2014. The proposed rule prescribes

technology standards for cooling water intake structures that would decrease interference

with fish and other aquatic organisms. Given that the Rockport and Mitchell units are

already equipped with natural draft, hyperbolic cooling towers, the most significant

potential impact of the proposed rule would be the need to install additional fish

screening at the front of the water intake structure.

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4.2.4.4.4 National Ambient Air Quality Standards (NAAQS)

The Clean Air Act requires the EPA to establish and periodically review NAAQS

designed to protect public health and welfare. Several NAAQS have been recently

revised or are under review, which could lead to more stringent SO2 and NO limits. This

includes NAAQS for SO2 (revised in 2010), NO2 (revised in 2010), fine particulate

matter (revised in 2012), and ozone (expected to be revised in 2014). The scope and

timing of potential requirements is uncertain.

4.2.4.4.5 GHG Regulations

For many years, the potential for requirements to reduce greenhouse gas

emissions, including carbon dioxide, has been one of the most significant issues facing

Kentucky Power and AEP. The EPA proposed GHG NSPS for fossil fuel-fired electric

generating units in April, 2012. This proposed rule applies only to new sources and

proposed an emission standard based on the performance of new natural gas combined

cycle units. The EPA did not finalize this rule as expected in the second quarter of 2013.

However, on June 25, 2013, President Obama announced a plan to address GHG

emissions from fossil-fired power plants. Under President Obama's direction, the EPA

issued a revised proposal for the GHG NSPS for new sources on September 20, 2013,

and must finalize them in a "timely fashion." For existing sources, the EPA was directed

to propose guidelines by June 1, 2014, and finalize those standards by June 1, 2015.

States would develop and submit a plan to EPA for implementing the existing source'

standards by June 30, 2016. The scope and timing of these requirements have not yet

been determined. Such GHG rules could impose greater operating costs on Kentucky

Power's power plants in future years, either through retrofit costs, efficiency

requirements, or potentially, some form of carbon tax and/or cap-and-trade construct.

4.2.4.5 Kentucky Power Environmental Compliance

This 2013 IRP considers the impacts of final and proposed EPA regulations to

Kentucky Power generating facilities, inclusive of Big Sandy Unit 1, Rockport and

Mitchell. In addition, the IRP development process assumes there will be future

regulation of GHG/CO2 emissions which would become effective at some point in the

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2022 timeframe. Emission compliance requirements have a major influence on the

consideration of new supply-side resources for inclusion in the IRP because of the

potential significant effects on both capital and operational costs. Moreover, the

cumulative cost of complying with these rules will ultimately have an impact on

proposed retirement dates of existing coal-fueled units that would otherwise be forced to

install emission control equipment.

4.3 Procedure to Formulate Long-Term Plan

(807 KAR 5:058 Sec.8.5.a.)

The following steps were involved to develop the resource plan presented in this

report. These steps are as follows:

1. Develop the base-case load forecast.

2. Determine overall resource requirements.

3. Identify and screen DSM options.

4. Identify and screen supply-side resource options.

5. Integrate supply-side and demand-side options.

a. Optimize expanded DSM programs.

b. Develop optimal supply-side resource expansion plans with expanded DSM.

6. Analyze and Review.

A discussion of these steps follows.

4.3.1 Develop Base-Case Load Forecast

The development of the base-case load forecast is presented in Chapter 2. That

initial forecast excludes adjustments for potential future (i.e., expanded) DSM programs

but does incorporate a continuation of currently approved programs.

4.3.2 Determine Overall Resource Requirements

The determination of overall resource requirements includes an evaluation of the

adequacy of existing generating capability to meet the future forecasted load and peak

demand requirements.

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ENTUCKY ER

4.3.2.1 Existing and Committed Generation Facilities (807 KAR 5:058 Sec.8.3.b.12.d., Sec. 8.3.d.)

Kentucky Power's existing installed generating capability (as of December, 2013)

is shown as part of Exhibit 4-2. Kentucky Power's owned capacity consists of the 1,078

MW Big Sandy generating plant, located in Louisa, Kentucky. Kentucky Power also has

a unit power agreement with AEP Generating Company (AEG), an affiliate, to purchase

15% (currently a total of 393 MW) of capacity from the two units at the Rockport Plant,

located in southern Indiana. Both Kentucky Power Rockport unit power agreements run

through December 7, 2022. For planning purposes, it has been assumed that the Rockport

agreements extend indefinitely beyond that expiration date. Starting January 1, 2014,

Kentucky Power will own 50%, or 780 MW, of both the Mitchell units, which are located

in West Virginia and are currently owned by affiliate Ohio Power Company (OPCo).

4.3.2.2 Retrofit or Life Optimization of Existing Facilities (807 KAR 5:058 Sec.8.2.a.)

Past experience has indicated that, with proper maintenance and operation, coal-

fired units can expect to achieve operating lifetimes beyond the traditional nominal 50 to

60 years. Of course, the optimum achievable lifetime is highly unit-specific. Programs

have been developed by AEP to attempt to achieve optimal operating lifetimes, and to do

so as economically as possible. The work of component refurbishment or replacement is

planned and carried out over a long period, so as to minimize total cost and the outage

time required. Ultimately, however, retirement of older units must be considered as units

become less economic from efficiency, cost, and environmental standpoints.

4.3.2.3 Renewable Energy Plans (807 KAR 5:058 Sec.8.2.d.)

The State of Kentucky does not have a renewable energy requirement or

renewable portfolio standard (RPS). Pursuant to the Mitchell Transfer Stipulation and

Settlement Agreement, Kentucky Power agreed to evaluate the prospect of a potential

purchase up to 100 MW of wind capacity. Renewable energy options are expected to

compete economically with traditional supply-side options in the future.

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4.3.2.4 Demands, Capabilities and Reserve Margins —Going-in

Exhibit 4-7 provides a projection of Kentucky Power's peak demands,

capabilities and reserve margins for the summer season from 2014 through 2028,

assuming no other new resources are added to the system. The projected data reflect the

`Base'-case load forecast, committed sales to non-affiliated utilities, and the amount of

Kentucky Power's industrial interruptible load that can be interrupted at the time of the

seasonal peak. The projected capabilities assume Big Sandy Unit 2 will be retired in

2015, and Big Sandy Unit 1 will be retired in 2031. It also assumes the transfer of 50%

ownership of Mitchell Units 1 and 2 in 2014. Further, until Rockport Units 1 and 2 are

fitted with full FGD "scrubbers," their output is subject to SO? emissions caps described

in the Third Modified NSR Consent Decree previously highlighted in Table 15.

4.3.3 Identify and Screen DSM Options

The identification and screening of DSM options is described in detail in Chapter

3 of this report.

4.3.4 Identify and Screen Supply-side Resource Options

(807 KAR 5:058 Sec.8.2.d. and Sec. 8.5.e.)

4.3.4.1 Capacity Resource Options (807 KAR 5:058 Sec.8.3.d. and Sec. 8.5.g.)

In addition to market capacity purchase options, new-build options were modeled

to represent peaking and baseload/intermediate capacity resource options. To reduce the

number of modeling permutations in Plexos® , the available technology options were

limited to certain representative unit types. However, it is important to note that

alternative technologies with comparable cost and performance characteristics may

ultimately be substituted should technological or market-based profile changes warrant.

The options assumed to be available for modeling analyses for Kentucky Power are

presented in Exhibit 4-9 of the Confidential Supplement. When applicable, Kentucky

Power may take advantage of economical market opportunities in the form of limited-

term bilateral capacity purchases and discounted generation asset purchases. Such market

opportunities could be utilized to hedge capacity planning exposures should they emerge

and create (energy) option value to the Company. Prospectively, these opportunities

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could take the place of currently planned resources and will be evaluated on a case-by-

case basis.

4.3.4.2 New Supply-side Capacity Alternatives

As identified in Exhibit 4-9 of the Confidential Supplement, natural gas

base/intermediate and peaking generating technologies were considered in this IRP as

well as utility-scale solar and wind. However, in an attempt to reduce the problem size

within the Plexos® modeling application, an economic screening process was used to

analyze various options and develop a quantitative comparison for each type of capacity

(baseload, intermediate, and peaking) on a forty-year, levelized basis. The options were

screened by comparing levelized annual busbar costs over a range of capacity factors.

In this evaluation, each type of technology is represented by a line showing the

relationship between its total levelized annual cost per kW and an assumed annual

capacity factor. The value at a capacity factor of zero represents the fixed costs, including

carrying charges and fixed O&M, which would be incurred even if the unit produced no

energy. The slope of the line reflects variable costs, including fuel, emissions, and

variable O&M, which increase in proportion to the energy produced.

The best of class technology determined by this screening process was taken

forward to the Plexos® model. These generation technologies were intended to represent

reasonable proxies for each capacity type (baseload, intermediate, peaking). Subsequent

substitution of specific technologies could occur in any ultimate plan, based on emerging

economic or non-economic factors not yet identified.

AEP's Generation organization is responsible for the tracking and monitoring of

estimated cost and performance parameters for a wide array of generation technologies.

Utilizing access to industry collaboratives such as EPRI and the Edison Electric Institute,

AEP's association with architect and engineering firms and original equipment

manufacturers as well as its own experience and market intelligence, this group

continually monitors supply-side trends. Table 17 offers a summary of the most recent

technology performance parameter data developed.

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A will of American Electric Power

Typo Capability OM)

Trans. Cost (e) (MIN)

Ernision Rates Capacity Overall Factor Availability

(%) ( 5 )

SO2 (g) NOx CO2 (lblmniBtu) (Lb/mm Btu) (Lb/mmlatu) Std. ISO

Base / Intermediate Combined Cycle (1X1 GE7FA.05) 300 60 0.0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05) 624 60 0.0007 0,009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05, w/ Duct Firing) 624 60 0,0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05, w/ Duct Firing, Inlet Chillers) 624 60 0.0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05, w/ Duct Firing, elk Start) 624 60 0.0007 0.009 116.0 60 89,1 Combined Cycle (1X1 SGT6-5000, w/ Evap Coolers) 294 60 0.0007 0.010 116.0 60 89,1 Combined Cycle (2X1 SGT6-5000, w/ Evap Coolers) 609 60 0,0007 0,010 116 0 60 89.1 Combined Cycle (2X1 KA24-2, w/ Evap Coolers) 647 60 0,0007 0.011 116.0 60 89.1 Combined Cycle (2X1 M501GAC, w/ Duct Firing, Inlet Chillers) 780 60 0.0007 0.007 116,0 60 894

Peeking Combustion Turbine (2X1GE7EA) 164 57 0.0007 0,033 116.0 3 93,0 Combustion Turbine (2X1GE7EA,w/ Blk Start) 164 57 0.0007 0,033 116.0 3 93,0 Combustion Turbine (2X1GE7EA, w/ Inlet Chillers) 164 59 0.0007 0,009 116.0 3 93.0 Combustion Turbine (2X1GE7FA.05, w/ Inlet Chillers) 418 59 0,0007 0.007 116.0 3 93,0 Aero-Derivative (1X GE LM6000PF) 45 60 0.0007 0,093 116,0 3 95.0 Aero-Derivative (2X GE LM6000PF) 91 60 0,0007 0,093 116.0 3 95.0 Aero-Derivative (2X GE LM6000PF, w/ Blk Start) 91 60 0,0007 0.093 116.0 3 95.0 Aero-Derivative (1X GE LMS100PB) 98 59 0,0007 0.011 116.0 30 95.0 Aero-Derivative (2X GE LMS100PB, w/ Elk Start) 196 59 0.0007 0.093 116,0 30 95,0 Aero-Derivative (2X GE LMS100PB, w/ Inlet Chillers) 196 59 0,0007 0.007 116.0 25 95.0 Wartsila 22 X 20V34SG 201 60 0,0007 0.018 116.0 3 94.0

(a) Installed cost, capability and heat rate numbers have been rounded. (b) All costs In 2012 dollars. Assume 1.61 escalation rate for 2012 and beyond. (c) SW/ casts are based on Standard ISO capability.

Notes, (e) Transmission Cost (5./kVV,w /A FLOC).

(g) Eased on 4.5 Ile, Coal.


Table 17: New Generation Technology Options

Key Supply-Side Resource Option Assumptions (a)(b)(c)

4.3.4.3 Baseload/Intermediate Alternatives

Coal and Nuclear baseload options were not included in this plan. For coal, the

proposed EPA New Source Performance Standards (MSPS) rulemakine effectively

makes the construction of new coal plants environmentally/economically impractical due

to the implicit requirement of carbon capture and sequestration (CCS) technology. For

new nuclear construction, it is financially impractical since it requires (minimally) a

$6,000/kW investment cost.

Intermediate generating sources are typically expected to serve a load-following and

cycling duty and shield baseload units from that obligation. Historically, many generators

have relied on older, smaller, less-efficient/higher dispatch cost, subcritical coal-fired

units to serve such load-following roles. Over the last several years, these units' staffs

have made strides to improve ramp rates, regulation capability, and reduce downturn

(minimum load capabilities). As the fleet continues to age and subcritical units are retired

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A unit of American Electric Pan 2013 Integrated Resource Plan

or refueled, other generation dispatch alternatives and new generation will need to be

considered to cost effectively meet this duty cycle's operating characteristics.

a. Natural Gas Combined Cycle (NGCC)

An NGCC plant combines a steam cycle and a combustion gas turbine cycle to

produce power. Waste heat (1,100°F) from one or more combustion turbines passes

through a heat recovery steam generator (HRSG) producing steam. The steam drives a

steam turbine generator which produces about one-third of the NGCC plant power,

depending upon the gas-to-steam turbine design "platform," while the combustion

turbines produce the other two-thirds.

The main features of the NGCC plant are high reliability, reasonable capital costs,

operating efficiency (at 45-60% Low Heating Value), low emission levels, small

footprint and shorter construction periods than coal-based plants. In the past 8 to 10

years, NGCC plants were often selected to meet new intermediate and certain baseload

needs. NGCC plants may be designed with the capability of being "islanded" which

would allow them, in concert with an associated diesel generator, to perform system

restoration ("black start") services. Although cycling duty is typically not a concern, an

issue faced by NGCC when load-following is the erosion of efficiency due to an inability

to maintain optimum air-to-fuel pressure and turbine exhaust and steam temperatures.

Methods to address these include:

® Installation of advanced automated controls.

Supplemental firing while at full load with a reduction in firing when load

decreases. When supplemental firing reaches zero, fuel to the gas turbine is

cutback. This approach would reduce efficiency at full load, but would

likewise greatly reduce efficiency degradation in lower-load ranges.

• Use of multiple gas turbines coupled with a waste heat boiler that will give the

widest load range with minimum efficiency penalty.

10 On March 27, 2012, the US EPA issued proposed NSPS for GHG emissions from new power plants pursuant to section 111 of the Clean Air Act (CAA).

127



4.3.4.4 Peaking Alternatives

Peaking generating sources provide needed capacity during extreme high-use

peaking periods and/or periods in which significant shifts in the load (or supply) curve

dictate the need for "quick-response" capability. The peaks occur for only a few hours

each year and the installed reserve requirement is predicated on a one day in ten year loss

of load expectation, so the capacity dedicated to serving this reliability function can be

expected to provide very little energy over an annual load cycle. As a result, fuel

efficiency and other variable costs are of less concern. This capacity should be obtained

at the lowest practical installed cost, despite the fact that such capacity often has very

high energy costs. This peaking requirement is manifested in the system load duration

curve.

In addition, in certain situations, peaking capacity such as combustion turbines can

provide backup and some have the ability to provide emergency (Black Start) capability

to the grid.

a. Simple Cycle Combustion Turbines (NGCT)

In "industrial" or "frame-type" combustion turbine systems, air compressed by an

axial compressor (front section) is mixed with fuel and burned in a combustion chamber

(middle section). The resulting hot gas then expands and cools while passing through a

turbine (rear section). The rotating rear turbine not only runs the axial compressor in the

front section but also provides rotating shaft power to drive an electric generator. The

exhaust from a combustion turbine can range in temperature between 800 and 1,150

degrees Fahrenheit and contains substantial thermal energy. A simple cycle combustion

turbine system is one in which the exhaust from the gas turbine is vented to the

atmosphere and its energy lost, i.e., not recovered as in a combined cycle design. While

not as efficient (at 30-35% LHV), they are inexpensive to purchase, compact, and simple

to operate.

b. Aeroderivatives (AD)

Aeroderivatives are aircraft jet engines used in ground installations for power

generation. They are smaller in size, lighter weight, and can start and stop quicker than

128

KENTUCKY ER


their larger industrial or "frame" counterparts. For example, the GE 7EA frame machine

requires 20 minutes to ramp up to full load while the smaller LM6000 aeroderivative

only needs 10 minutes from start to full load. However, the cost per kW of an

aeroderivative is on the order of 20% higher than a frame machine.

The AD performance operating characteristics of rapid startup and shutdown make

the aeroderivatives well suited to peaking generation needs. The aeroderivatives can

operate at full load for a small percentage of the time allowing for multiple daily startups

to meet peak demands, compared to frame machines which are more commonly expected

to start up once per day and operate at continuous full load for 10 to 16 hours per day.

The cycling capabilities provide aeroderivatives the ability to backup variable renewables

such as solar and wind. This operating characteristic is expected to become more

valuable over time as: a) the penetration of variable renewables increase; b) baseload

generation processes become more complex limiting their ability to load follow and; c)

intermediate coal-fueled generating units are retired from commercial service.

AD units weigh less than their industrial counterparts allowing for skid or modular

installations. Efficiency is also a consideration in choosing an aeroderivative over an

industrial turbine. Aeroderivatives in the less than 100 MW range are more efficient and

have lower heat rates in simple cycle operation than industrial units of equivalent size.

Exhaust gas temperatures are lower in the aeroderivative units.

Some of the better known aeroderivative vendors and their models include GE's LM

series, Pratt & Whitney's FT8 packages, and the Rolls Royce Trent and Avon series of

machines."

4.3.4.5 Renewable Alternatives

Renewable generation alternatives use energy sources that are either naturally

occurring (wind, solar, hydro or geothermal), or are sourced from a by-product or waste-

Turbomachinery International, Jan/Feb. 2009; Gas Turbine World; EPRI TAG.

129

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product of another process (biomass or landfill gas). In the recent past, development of

these resources has been driven primarily as the result of renewable portfolio

requirements. That is not universally true now as advancements in both solar PV and

wind turbine manufacturing have brought costs down.

Because wind resources are not always productive during the time of system peak,

these resources are assumed to have "useful capacity" equivalent to 13-14% of their

nameplate capacity within PJM.

a. Utility-Scale Solar

Solar power takes a couple of viable forms to produce electricity: concentrating and

photovoltaics. Concentrating solar — which heats a working fluid to temperatures

sufficient to power a turbine - produces electricity on a large scale and is similar to

traditional centralized supply assets in that way. Photovoltaics produce electricity on a

smaller scale (2 kW to 20 MW per installation) and can be distributed throughout the

grid. Figure 11 shows the potential solar resource locations in the U.S.

Figure 11: United States Solar Power Locations

The cost of solar panels has declined considerably in the past decade. This has been

mostly a result of reduced panel prices that have resulted from manufacturing efficiencies

spurred by accelerating penetration of solar energy in Europe, Japan, and California.

130

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With the trend firmly established, forecasts generally foresee declining nominal prices in

the next decade as well.

Not only are utility scale solar plants getting less expensive, the costs to install solar

panels in distributed locations, often on a rooftop, are lessening as associated hardware,

such as inverters, racks, and wiring bundles become standardized (See Figure 12). If the

projected cost declines materialize, both distributed and utility scale solar projects will be

economically justifiable in the future.

Figure 12: Solar Panel Installed Cost

Utility solar plants require less lead time to build than fossil plants. There is not a

defined limit to how much utility solar can be built in a given time. However, in practice,

solar facilities are not added in an unlimited fashion. Figure 13 shows the density of

solar installations by county, with the vast majority of counties in PJM having less than I

MW of solar installed. In the period from July 2012 — June 2013, solar photovoltaic

constituted less than one-tenth of one percent of total generation in PJM.

For this reason, solar resources were considered available resources with some

limits on the rate with which they could be chosen. Utility solar resources were made

available up to 10 MW of incremental nameplate capacity starting in 2014. To provide

131

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some context around that, a typical commercial installation is 50 kW and effectively

covers the surface of a typical "big box" retailer's roof. A 50 MW utility-scale solar

"farm" consumes nearly 150 acres.

As with wind resources, solar resources' useful capacity is less than its nameplate

rating. In PJM, that capacity credit is 38% of the nameplate rating. PJM's peak is in the

late afternoon, around 5 p.m., well past the point that solar panels are producing at their

peak, typically 1 p.m.

Time will tell whether solar can be implemented at a pace that approaches the limits

incorporated, or perhaps, even exceed those limits.

Figure 13: Density of Solar Installation by County

b. Wind

b.1 Modeling Wind Resources

Utility wind energy is generated by wind turbines with a range 1.0 to 2.5 MW, with

a 1.5 MW turbine being the most common size used in commercial applications today

132

2006 2007 2008 2009 2010 2011 2012

wind natural gas other

12

10

8

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KENTUCKY ER


with over 60,000 MW I2 of wind online in the United States as of December 31, 2012.

Figure 14 shows the annual electric generating capacity additions by fuel.

Figure 14: Annual Electric Generating Capacity Additions by Fuel

Annual electric generating capacity additions by fuel, 2006-2012 gigawatts

14

Typically, multiple wind turbines are grouped in rows or grids to develop a wind

turbine power project which requires only a single connection to the transmission system.

Location of wind turbines at the proper site is particularly critical as not only does the

wind resource vary by geography, but its proximity to a transmission system with

available capacity will factor into the cost.

Ultimately, as turbine production increases to match the significant increase in

demand, the high capital costs of wind generation should begin to decline. Currently, the

cost of electricity from wind generation is becoming competitive within PJM due largely

to subsidies, such as the federal production tax credit as well as consideration given to

(renewable energy certificate) REC values, if available, anticipated rising fuel costs and

potential future carbon costs.

12 Data is from the American Wind Energy Association (AWEA) Fourth Quarter 2012 Market Report (http://www.awea.org).

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A variable source of power in most non-coastal locales, with capacity factors

ranging from 30 percent (in the eastern portion of the U.S.) to 50 percent (largely in more

westerly portions of the U.S., including the Plains states), wind energy's life-cycle cost

($/MWh), excluding subsidies, is currently higher than the marginal (avoided) cost of

energy, in spite of its negligible operating costs. Another obstacle with wind power is that

its most critical factors (i.e., wind speed and sustainability) are typically highest in very

remote locations, and this forces the electricity to be transmitted long distances to load

centers necessitating the build out of EHV transmission to optimally integrate large

additions of wind into the grid. In the PJM region, wind is credited with 13% useful

capacity, or wind turbines are, on average, producing at 13% of nameplate capacity at the

time of PJM peak.

For modeling purposes, wind was considered under various timing and 'blocks'.

Initially, information emanating from the Company's October 18, 2013, RFI was utilized

to establish the prospect for a "nearer-term" (2017) wind resource opportunity. The cost

and performance parameters provided in response to that RFI were summarized and

grouped into the modeling based on whether the propsective offers were domiciled in

Kentucky or "adjacent" to the state. Those prospective offers were then averaged, in a

maximum annual block size of 100 MW, according to such grouping. Further, an

additional near-term tranche of no more than 100 MW was considered which did

incorporate the prospect of receiving federal PTC. For periods beyond 2017, such wind

resources were considered using more "generic" cost and performance parameters, rather

than information derived from the indicative RFI process. Those outer-year wind

resources were also considered to be available in maximum 100 MW blocks at a cost

according to the schedule shown in Figure 15 with no prospect of the federal PTC which

expires for projects not initiated before year-end 2013.

Further, for this IRP, wind resources are modeled as a REPA with the implicit

`build' costs assumed to decline over time, reflecting both increased efficiency or

capacity factor of the turbines and decreasing manufacturing cost. While Kentucky is not

rich in wind resources (see Figure 16), adjoining states such as Ohio, Indiana, Illinois,

134

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and Missouri may provide suitable sites for construction with limited requirements to

build additional transmission.

Figure 15: Utility Wind Cost Assumption

Figure 16 shows the wind resource locations in the U.S. and their relative potential.

Figure 16: United States Wind Power Locations

135

KENTUCKY ER


c. Hydro

The available sources of, particularly, larger hydroelectric potential have largely

been exploited and those that remain must compete with the other uses, including

recreation and navigation. The potentially lengthy time associated with environmental

studies, Federal Army Corp of Engineer permitting, high up-front construction costs, and

environmental issues (fish and wildlife) make hydro prohibitive at this time. No

incremental hydroelectric resources were considered in this IRP.

d. Biomass

Biomass is a term that typically includes organic waste products (sawdust or other

wood waste), organic crops (corn, switchgrass, poplar trees, willow trees, etc.), or biogas

produced from organic materials, as well as select other materials. Biomass costs will

vary significantly depending upon the feedstock. Biomass is typically used in power

generation through the utilization of the biomass fuel in a steam generator (boiler) that

subsequently drives a steam turbine generator; similar to the same process of many

traditional coal fired generation units. Some biomass generation facilities use biomass as

the primary fuel, however, there are some existing coal-fired generating stations that will

use biomass as a blend with the coal.

The ecoPower biomass REPA is a 58.5 MW facility that burns waste wood

generated by the lumber industry, and is slated for operation by 2017. Kentucky Power

has agreed to purchase the power from this facility as part of a negotiated settlement

agreement approved by the Commission.

e. Cogeneration

Cogeneration is a process where electricity is generated and the waste heat by-

product is used for heating or other process, raising the net thermal efficiency of the

plant. Currently, there is no co-generation or combined heat and power (CHP) on

Kentucky Power's system. To take advantage of the increased efficiency associated with

CHP, the host must have a ready need for the heat that is otherwise potentially wasted in

the generation of electricity. In AEP's service territory, there are over 3,400 MW of CHP

136

0.7% AEP CHP by End-use OS 3 % 0%

1.1% 1.0%_, — 0.3%

• Chemicals

• Refining

II Pulp and Paper

• Primary Metals

M Colleges/Univ.

• Food Processing

rn District Energy

sti Hospitals/Healthcare

Other

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KENTUCKY POWER'



which serve the following industries (See Figure 17). The bulk of this CHP capacity is in

Texas and Louisiana.

Figure 17: AEP CHP by End-use

The refining industry is a sizable part of Kentucky Power's industrial sector

consumption, and it is concentrated in a single customer. Historically, Kentucky Power's

low cost combined with the relatively high cost of natural gas, a primary fuel for

cogeneration facilities, has made cogeneration uneconomical in Kentucky Power's

service territory. Kentucky Power is occasionally approached by customers for help in

evaluating CHP and co-generation opportunities, but the Company's relatively low

avoided costs have been a significant barrier to-date for any serious implementation

consideration.

4.3.5 Integrate Supply-Side and Demand-Side Options

The Plexos® model was used to study the long-term integration and optimization

of various resource alternatives, and requires projections of various external parameters

that primarily are driven by market forces. The input variables to the forecasts of these

parameters include forecasts of fuels, load, emissions, emission retrofits, construction

costs for capital projects, and others. Each input variable is shaped by government-

provided historical data, government forecasts, leading energy-industry consultancies,

137

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A unit of Amen Electric Power 2013 Integrated Resource Plan

AEP-internal views and the output of industry-accepted modeling tools, which apply

economic principles and dispatch simulation to model the relationships of utility supply,

transmission and demand to forecast market prices. The refinement of modeling analysis

is continuous, but is immediately oriented toward emissions, renewables, volatile

commodity prices and changing economic conditions.

4.15.1 Optimize Expanded DSM Programs

As described in Chapter 3, EE and VVO options that would be incremental to the

current programs were modeled as resources within Plexos' . In this regard, they are

"demand-side power plants" that produce energy according to their end use load shape.

They have an initial (program) cost with no operating costs. They are "retired" at the end

of their useful lives.

4.3.5.2 Optimize Other Demand-Side Resources

Customer-sited distributed generation, specifically distributed solar generation,

was modeled as a purchase power agreement with the cost to the utility being the full

retail rate, consistent with current net metering tariffs.

4.3.6 Analysis and Review

To develop the "Preferred Portfolio," Kentucky Power built resource portfolios

that were optimized under five separate economic scenarios. These scenarios are

described in Section 4.6.4. These five unique portfolios form the basis for the Preferred

Portfolio resource plan, which is then further evaluated under a distribution of economic

futures, often referred to as a Monte Carlo analysis, to determine the relative economic

"risk" of the plan.

Kentucky Power's preferred plan presented herein is expected to provide

adequate reliability over the forecast period.

The long-term capacity schedule reported herein is simply a snapshot of the future

at this time, based on current thinking relative to various parameters, each having its own

degree of uncertainty. The expansion reflects, to a large extent, assumptions that are

subject to change. As the future unfolds, and as parameter changes are recognized and

138



updated, input information are continually evaluated, and resource plans modified as

appropriate.

Some key factors that can affect the timing of future capacity additions are the

magnitude of future loads and capacity reserve requirements. The magnitude of the future

load in any particular year is a function of load growth and DSM impacts. Capacity

reserve requirements, as previously discussed, could vary depending on the average

system generating-unit availability of both Kentucky Power and PJM.

4.4 Other Considerations and Issues

4.4.1 Transmission System

(807 KAR 5:058 Sec.5.4.)

4.4.1.1 General Description

The AEP-East Transmission System (eastern zone) consists of the transmission

facilities of the six eastern AEP operating companies (Kentucky Power, Appalachian

Power Company, Ohio Power Company, Indiana Michigan Power Company, Wheeling

Power Company and Kingsport Power Company). This portion of the Transmission

System is composed of approximately 15,000 miles of circuitry operating at or above 100

kV. The eastern zone includes over 2,100 miles of 765 kV overlaying 3,800 miles of 345

kV and over 8,900 miles of 138 kV circuitry. This expansive system allows AEP to

economically and reliably deliver electric power to approximately 24,200 MW of

customer demand connected to the AEP-East Transmission System that takes

transmission service under the PJM open access transmission tariff (OATT).

The AEP-East Transmission System is part of the Eastern Interconnection; the

most integrated transmission system in North America. The entire AEP-East

Transmission System is located within the ReliabilityFirst (RFC) geographic area. On

October 1, 2004, AEP's eastern zone joined the RTO and now participates in the PJM

markets.

As a result of the AEP-East Transmission System's geographical location and

expanse as well as its numerous interconnections, the eastern Transmission System can

be influenced by both internal and external factors. Facility outages, load changes, or

139

KENTUCKY POWER


generation re-dispatch on neighboring companies' systems, in combination with power

transactions across the interconnected network, can affect power flows on AEP's

transmission facilities. As a result, the AEP-East Transmission System is designed and

operated to perform adequately even with the outage of its most critical transmission

elements or the unavailability of generation. The eastern zone conforms to the NERC

Reliability Standards and applicable RFC standards and performance criteria.

Despite the robust nature of the eastern zone, certain outages coupled with

extreme weather conditions and/or power-transfer conditions can potentially stress the

system beyond acceptable limits. The most significant transmission enhancement to the

AEP-East Transmission System over the last few years was completed in 2006. This was

the construction of a 90-mile 765 kV transmission line from Wyoming Station in West

Virginia to Jacksons Ferry Station in Virginia. In addition, EHV/138 kV transformer

capacity has been increased at various stations across the eastern Transmission System.

AEP's eastern zone assets are aging. Figure 18 demonstrates the development of

AEP's eastern Transmission Bulk Electric System. In order to maintain reliability,

significant investments will have to be made in the rehabilitation of existing assets over

the next decade.

Figure 18: Transmission Bulk Electric System Development

Introduction of 138 kV

Introduction of 345 kV

[Introduction of 765 kV

36 Years

16 Years

1917

1953 1969

Over the years, AEP, and now PJM, entered into numerous study agreements to

assess the impact of the connection of potential merchant generation to the eastern zone.

Currently, there is more than 26,000 MW of AEP generation and approximately 6,000

MW of additional merchant generation connected to the eastern zone. AEP, in

conjunction with PJM, has interconnection agreements in the AEP service territory with

140

1(ENTUCUY ER


several merchant plant developers for approximately 1,000 MW of additional generation

to be connected to the eastern zone over the next several years. There are also significant

amounts of merchant generation under study for potential interconnection.

The integration of the merchant generation now connected to the eastern zone

required incremental transmission system upgrades, such as installation of larger capacity

transformers and circuit breaker replacements. None of these merchant facilities required

major transmission upgrades that signif►cantly increased the capacity of the transmission

network. Other transmission system enhancements will be required to match general load

growth and allow the connection of large load customers and any other generation

facilities. In addition, transmission modifications may be required to address changes in

power flow patterns and changes in local voltage profiles resulting from operation of the

PJM and Midwest ISO markets.

The announced retirement of approximately 13,000 MW of generation in PJM,

including 800 MW at the Big Sandy plant, will result in the need for power to be

transmitted over a longer distance into the Kentucky area. In addition, these retirements

will result in the loss of dynamic voltage regulation. Upon formal notification of

retirement to PJM, the Big Sandy unit will be subject to deactivation studies to ensure

reliability is not compromised by the retirement of the generation.

There are two areas in particular that will receive transmission enhancements to

allow the reliable operation of the Kentucky Power transmission system.

The Hazard Area Improvement Plan includes a comprehensive 138 kV

transmission system improvement plan for implementation in AEP's Hazard,

Kentucky area. Once implemented, the plan will alleviate thermal overloads, low

voltage concerns, and improve transmission service reliability to the Hazard Area.

This proposal includes establishing a new 138 kV source from Beaver Creek

Station via Soft Shell Station to the Hazard area. A new twenty (20) mile line will

be constructed from Soft Shell Station to Bonnyman Station to establish a second

138 kV source into the Hazard transmission system. These facilities are proposed

to be in service by December 2014.

PJM's 2015 Summer Regional Transmission Expansion Plan (RTEP) study

revealed overloads on 345 kV and 138 kV facilities in the Tristate area during

single-contingency outage conditions. System studies by AEP found that all of

141

f;21-i" KENTUCKY P1 POWER


these overloads could be alleviated by the installation of a second 765/345 kV

transformer at the Baker Station in Kentucky. AEP has proposed a project to

install a second Baker 765/345 kV transformer, as well as install two 765 kV and

three 345 kV circuit breakers.

The transmission line miles in Kentucky include approximately 258 miles of 765

kV, 9 miles of 345 kV, 46 miles of 161 kV, 309 miles of 138 kV lines, 437 miles of 69

kV, and 147 miles of 46 kV lines. Confidential Exhibit 4-16 displays a map of the entire

AEP System-East Zone transmission grid, including Kentucky Power Company.

4.4.1.2 Transmission Planning Process

AEP and PJM coordinate the planning of the transmission facilities in the AEP

System-East Zone through a "bottom up/top down" approach. AEP will continue to

develop transmission expansion plans to meet the applicable reliability criteria in support

of PJM's transmission planning process. PJM will incorporate AEP's expansion plans

with those of other PJM member utilities and then collectively evaluate the expansion

plans as part of its RTEP process. The PJM assessment will ensure consistent and

coordinated expansion of the overall bulk transmission system within its footprint. In

accordance with this process, AEP will continue to take the lead for the planning of its

local transmission system under the provisions of Schedule 6 of the PJM Operating

Agreement (OA). By way of the RTEP, PJM will ensure that transmission expansion is

developed for the entire RTO footprint via a single regional planning process, assuring a

consistent view of needs and expansion timing while minimizing expenditures. When the

RTEP identifies system upgrade requirements, PJM determines the individual member's

responsibility as related to construction and costs to implement the expansion. This

process identifies the most appropriate, reliable and economical integrated transmission

reinforcement plan for the entire region while blending the local expertise of the

transmission owners such as AEP with a regional view and formalized open stakeholder

input.

AEP's transmission planning criteria is consistent with NERC and

ReliabilityFirst reliability standards. The AEP planning criteria are filed with FERC

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annually as part of AEP's FERC Form 715 and these planning criteria are posted on the

AEP website.'3 Using these criteria, limitations, constraints and future potential

deficiencies on the AEP transmission system are identified. Remedies are identified and

budgeted as appropriate to ensure that system enhancements will be timed to address the

anticipated deficiency.

PJM also coordinates its regional expansion plan on behalf of the member utilities

with the neighboring utilities and/or RTOs, including the Midwest ISO, to ensure inter-

regional reliability. The Joint Operating Agreement between PJM and the Midwest ISO

provides for joint transmission planning.

4.4.1.3 System-Wide Reliability Measure

At the present time, there is no single measure of system-wide reliability that

covers the entire system (transmission, distribution, and generation). However, in

practice, transmission reliability studies are conducted routinely for seasonal, near-term,

and long-term horizons to assess the anticipated performance of the transmission system.

The reliability impact of resource adequacy (either supply- or demand-side) would be

evaluated as an inherent part of these overall reliability assessments. If reliability studies

indicate the potential for inadequate transmission reliability, transmission expansion

alternatives and/or operational remedial measures would be identified.

4.4.1.4 Evaluation of Adequacy for Load Growth

As part of the on-going near-term/long-term planning process, AEP uses the latest

load forecasts along with information on system configuration, generation dispatch, and

system transactions to develop models of the AEP transmission system. These models are

the foundation for conducting performance appraisal studies based on established criteria

to determine the potential for overloads, voltage problems, or other unacceptable

131ittp://www.aep.com/about/codeofconduct/OASIS/TransmissionStudies/GuideLines/2013%20A EP%2OPJM%2OFERC%20715 jinalpart%204.pdf

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operating problems under adverse system conditions. Whenever a potential problem is

identified, AEP seeks solutions to avoid the occurrence of the problem. Solutions may

include operating procedures or capital transmission reinforcements. Through this on-

going process, AEP works diligently to maintain an adequate transmission system able to

meet forecasted loads with a high degree of reliability.

In addition, PJM performs a Load Deliverability assessment on an annual basis

using a 90/1014 load forecast for areas that may need to rely on external resources to meet

their demands during an emergency condition.

4.4.1.5 Evaluation of Other Factors

As a member of PJM, and in compliance with FERC Orders 888 and 889, AEP is

obligated to provide sufficient transmission capacity to support the wholesale electric

energy market. In this regard, any committed generator interconnections and firm

transmission services are taken into consideration under AEP's and PJM's planning

processes. In addition to providing reliable electric service to AEP's retail and wholesale

customers, PJM will continue to use any available transmission capacity in the AEP-East

transmission system to support the power supply and transmission reliability needs of the

entire PJM — Midwest ISO joint market.

A number of generation requests have been initiated in the PJM generator

interconnection queue. AEP currently has two active queue positions within Kentucky

totaling approximately 647 MW (capacity). Of these two active queue positions, one is a

biomass generation request and the other is a natural gas request. AEP, through its

membership in PJM, is obligated to evaluate the impact of these projects and construct

the transmission interconnection facilities and system upgrades required to connect any

projects that sign an interconnection agreement. The amount of planned generation that

will actually come to fruition is unknown at this time.

14 90% probability that the peak actual load will be lower than the forecasted peak load and 10% probability that the acutal peak load will be higher than the forecasted peak load.

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4.4.1.6 Transmission Expansion Plans

The transmission system expansion plans for the AEP eastern zone are developed

to meet projected future requirements. AEP uses power flow analyses to simulate normal

conditions, and credible single and double contingencies to determine the potential

thermal and voltage impact on the transmission system in meeting the future

requirements.

As discussed earlier, AEP will continue to develop transmission reinforcements to

serve its own load areas, in coordination with PJM, to ensure compatibility, reliability

and cost efficiency.

4.4.1.7 Transmission Project Descriptions

A detailed list and discussion of the AEP transmission projects that have recently

been completed or presently underway in Kentucky can be found under section 4.4.1.9

(Kentucky Transmission Projects) of this report. In addition, several other projects

beyond the Kentucky Power area have also been completed or are underway across the

AEP System-East Zone in PJM. While they do not directly impact Kentucky Power, such

additions contribute to the robust health and capacity of the overall transmission grid,

which also benefit Kentucky customers.

AEP's transmission system is anticipated to continue to perform reliably for the

upcoming peak load seasons. AEP will continue to assess the need to expand its system

to ensure adequate reliability for Kentucky Power customers within the Commonwealth

of Kentucky. AEP anticipates that incremental transmission expansion will continue to

provide for expected load growth.

4.4.1.8 FERC Form 715 Information

A discussion of the eastern AEP System reliability criteria for transmission

planning, as well as the assessment practice used, is provided in AEP's FERC Form 715

Annual Transmission Planning and Evaluation Report, 2013 filing. That filing also

provides transmission maps, and pertinent information on power flow studies and an

evaluation and continued adequacy assessment of AEP's eastern zone.

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As the Transmission Planner for AEP and AEP subsidiaries in the east, PJM

performs all required studies to assess the robustness of the Bulk Electric System. All the

models used for these studies are created by and maintained by PJM with input from all

Transmission Owners, including AEP and its subsidiaries. Any request for current cases,

models, or results should be requested from PJM directly. PJM is responsible for

ensuring that AEP meets all NERC transmission planning requirements, including

stability of the system.

Performance standards establish the basis for determining whether system

response to credible events is acceptable. Depending on the nature of the study, one or

more of the following performance standards will be assessed: thermal, voltage, relay,

stability, and short circuit. In general, system response to events evolves over a period of

several seconds or more. Steady state conditions can be simulated using a power flow

computer program. A short circuit program can provide an estimate of the large

magnitude currents, due to a disturbance, that must be detected by protective relays and

interrupted by devices such as circuit breakers. A stability program simulates the power

and voltage swings that occur as a result of a disturbance, which could lead to

undesirable generator/relay tripping or cascading outages. Finally, a post-contingency

power flow study can be used to determine the voltages and line loading conditions

following the removal of faulted facilities and any other facilities that trip as a result of

the initial disturbance.

The planning process for AEP's transmission network embraces two major sets of

contingency tests to ensure reliability. The first set, which applies to both bulk and local

area transmission assessment and planning, includes all significant single contingencies.

The second set, which is applicable only to the Bulk Electric System, includes multiple

and more extreme contingencies. For the eastern AEP transmission system, thermal and

voltage performance standards are usually the most constraining measures of reliable

system performance.

Sufficient modeling of neighboring systems is essential in any study of the Bulk

Electric System. Neighboring company information is obtained from the latest regional

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or interregional study group models, the RFC base cases, the Eastern Interconnection

Reliability Assessment Group (ERAG) and the Multiregional Modeling Working Group

(MMWG) power flow library, the PJM base cases, or the neighboring company itself. In

general, sufficient detail is retained to adequately assess all events, outages and changes

in generation dispatch, which are contemplated in any given study.

4.4.1.9 Kentucky Transmission Projects

A brief summary of the transmission projects in Kentucky Power's service

territory for the next five years is provided below. Project information includes the

project name, a brief description of the projects scope, and the projected in-service year.

• Hazard Area Improvements Projects — This project, which includes the

Bonnyman-Softshell line, will provide another 138 kV source of power into the

Hazard area of eastern Kentucky. This project also includes associated station

work. Once implemented, the plan will alleviate thermal overloads, low voltage

concerns, and improve transmission service reliability to the Hazard Area. The

projected in-service date for this project is December 2014.

• Big Sandy Area Improvements — This project will install a second 765/345 kV

transformer at Kentucky Power Company's Baker 765 kV station, as well as two

765 kV and three circuit breakers at the station. The projected in-service date for

this project is June 2015.

• Thelma and Busseyville Station Upgrades — This project includes station and

line work along the Big Sandy — Thelma 138 kV circuit. It will address thermal

overload concerns on the Big Sandy-Thelma 138 kV circuit. The projected in-

service date for this project is June 2015.

• Johns Creek and Stone Station Upgrades — This project will install two new

138 kV circuit breakers at Johns Creek and one 138 kV circuit breaker at Stone

Station. This project will provide enhanced reliability to customers, operational

flexibility, and voltage support. The projected in-service date for this project is

June 2015.

• Dorton 138 kV Circuit Breaker Project — This project will install three 138 kV

circuit breakers and one circuit switcher at Dorton Station. This project will

address thermal loading concerns and operational reliability concerns. The

projected in-service date for this project is June 2015.

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• Cedar Creek Station Upgrades — This project will install two new 138 kV

circuit breakers at Cedar Creek Station. This project will provide operational

benefits and provide voltage support for single-contingency line outages. The

projected in-service date for this project is April 2016.

4.4.2 Fuel Adequacy and Procurement

a. General

The generating units of Kentucky Power are expected to have adequate fuel

supplies to meet full-load burn requirements in both the short-term and the long-term.

AEPSC, acting as agent for Kentucky Power, is responsible for the procurement and

delivery of coal to Kentucky Power's generating stations, as well as setting coal inventory

target level ranges and monitoring those levels. AEPSC's primary objective is to assure a

continuous supply of quality coal at the lowest cost reasonably possible. Deliveries are

arranged so that sufficient coal is available at all times. The consistency and quality of

the coal delivered to the generating stations is also vitally important. The consistency of

the sulfur content of the delivered coal is fundamental to Kentucky Power in achieving

and maintaining compliance with the applicable environmental limitations.

b. Units

Kentucky Power relies on three coal-fired generating stations, Big Sandy,

Rockport and Mitchell for its energy and capacity requirements. The Big Sandy

generating station is located in Louisa, KY, and consists of two units with a total of 1,078

MW. Unit 1 is scheduled to be converted to exclusively burn natural gas and Unit 2 is

scheduled to retire in 2015. The Rockport Generating Station, located in Spencer County,

IN, consists of two 1,300 MW coal fired generating units. SO2 emissions at Rockport are

limited to 1.2 lb. SO2/MMBtu. Compliance with the emission limit is achieved by using a

blend of Powder River Basin low sulfur sub-bituminous coal and low sulfur bituminous

coal from Colorado or eastern sources. The Mitchell generating station (50% of which

will transfer to Kentucky Power in 2014) is located in Captina, WV and consists of two

units with a total of 1,560 MW.

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c. Procurement Process

Coal delivery requirements are determined by taking into account existing coal

inventory, forecasted coal consumption, and adjustments for contingencies that

necessitate an increase or decrease in coal inventory levels. Sources of coal are

established by taking into account contractual obligations and existing sources of supply.

Kentucky Power's total coal requirements are met using a portfolio of long-term

arrangements, and spot-market purchases. Long-term contracts support a relatively stable

and consistent supply of coal. When needed, spot purchases are used to provide

flexibility in scheduling contract deliveries to accommodate changing demand and to

cover shortfalls in deliveries caused by force majeure and other unforeseeable or

unexpected circumstances. Occasionally, spot purchases may also be made to test-burn

any promising and potential new long-term sources of coal in order to determine their

acceptability as a fuel source in a given power plant's generating units.

d. Inventory

Kentucky Power attempts to maintain in storage at each plant an adequate coal

supply to meet full-load burn requirements. However, in situations where coal supplies

fall below prescribed minimum levels, programs have been developed to conserve coal

supplies. In the event of a severe coal shortage, Kentucky Power would implement

procedures for the orderly reduction of the consumption of electricity, in accordance with

the Emergency Operating Plan.

e. Forecasted Fuel Prices

Kentucky Power specific forecasted annual fuel prices, by unit, for the period

2014 through 2028 are displayed in Exhibit 4-4 of the Confidential Supplement.

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4.5 Resource Planning Models

(807 KAR 5:058 Sec.8.5.a. and Sec.8.5.c.)

Information which describes the planning models (apart from the load forecasting

models) utilized by Kentucky Power in developing its integrated resource plans is

provided below.

4.5.1 Plexos Model

Plexos" LP long-term optimization model, also known as "LT Plan ," served as the

basis from which the Kentucky Power-specific capacity requirement evaluations were

examined and recommendations were made. The LT Plan® model finds the optimal

portfolio of future capacity and energy resources, including DSM additions that

minimizes the cumulative present worth (CPW) of a planning entity's generation-related

variable and fixed costs over a long-term planning horizon.

Plexos® accomplishes this by an objective function which seeks to minimize the

aggregate of the following capital and production-related (energy) costs of the portfolio

of resources:

• Fixed costs of capacity additions, i.e., carrying charges on incremental

capacity additions (based on a Kentucky Power-specific, weighted average

cost of capital), and fixed O&M;

• Fixed costs of any capacity purchases;

• Program costs of (incremental) DSM alternatives;

• Variable costs associated with Kentucky Power's generating units. This

includes fuel, start-up, consumables, market replacement cost of emission

allowances, and/or carbon 'tax,' and variable O&M costs;

• Distributed, or customer-domiciled resources were effectively cost out at the

equivalent of a full-retail "net metering" credit to those customers (i.e., a

"utility" perspective); and

• A 'netting' of the production revenue made into the PJM power market from

Kentucky Power's generation resource sales and the cost of energy — based on

unique load shapes from PJM purchases necessary to meet Kentucky Power's

load obligation.

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Plexos® executes the objective function described above while abiding by the

following possible constraints:

•

Minimum and maximum reserve margins;

® Resource addition and retirement candidates (i.e., maximum units built);

• Age and lifetime of generators;

• Retrofit dependencies (SCR and FGD combinations);

• Operation constraints such as ramp rates, minimum up/down times, capacity,

heat rates, etc.;

• Fuel burn minimum and maximums;

• Emission limits on effluents such as SO? and NOx; and

• Energy contract parameters such as energy and capacity.

The model inputs that compose the objective function and constraints are considered

in the development of an integrated plan that best fits the utility system being analyzed.

Plexos® does not develop a full regulatory cost-of-service (COS) profile. Rather, it

typically considers only the relative generation (G)-COS that changes from plan-to-plan,

and not fixed "embedded" costs associated with existing generating capacity and

demand-side programs that would remain constant under any scenario. Likewise,

transmission costs are included only to the extent that they are associated with new

generating capacity, or are linked to specific supply alternatives. In other words, generic

(nondescript or non-site-specific) capacity resource modeling would typically not

incorporate significant capital spends for transmission interconnection costs.

4.5.2 Demand-Side Screening

For a description of DR/EE screening, see Chapter 3, Section 3.4.

4.6 Major Modeling Assumptions

4.6.1 Planning & Study Period

The economic evaluations of this planning process were carried out over a 2014-

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2028 planning period with discrete economic costs examined beyond that, through 2040,

and terminal "end-effects" thereafter.

4.6.2 Load & Demand Forecast

The internal load and peak demand forecast is based on the July 2013 load

forecast.

4.6.3 Capacity Modeling Constraints

The major system limitations that were modeled by use of constraints are elaborated

on below. The LT Plan , LP optimization algorithm operates constraints in tandem with

the objective function in order to yield the least-cost resource plan.

• Maintain a PJM-required minimum reserve margin of roughly 15.6% per year

as represented earlier in this report on the Kentucky Power "going-in"

capacity position chart.

• Under the terms of the NSR Consent Decree (and Modified NSR Consent

Decree), Kentucky Power and AEP agreed to annual SO2 and NOx emission

limits for the AEP-East fleet of 16 coal-fueled power plants in Kentucky,

Indiana, Ohio, Virginia and West Virginia, inclusive of Kentucky Power

units.

® The restriction for consideration of new generation additions was assumed to

not precede the PJM 2017/18 planning year given the typical minimal —5-year

timeframe to approve, permit, design and engineer, procure materials,

construct and commission new fossil generation resources.

There are many variants of available supply-side and demand-side resource

options and types. It is a practical limitation that not all known resource types are made

available as modeling options. A screening of available supply-side technologies was

performed with the optimum assets made subsequently available as options. Such screens

for supply alternatives were performed for each of the major duty cycle "families"

(baseload, intermediate, and peaking).

The selected technology alternatives from this screening process do not

necessarily represent the optimum technology choice for that duty-cycle family. Rather,

they reflect proxies for modeling purposes.

Other factors will be considered that will determine the ultimate technology type

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(e.g., choices for peaking technologies: GE frame machines "E" or "F," GE LMS100 AD

machines). The full list of screened supply options is included in Exhibit 3 of the

Confidential Supplement.

Based on the established comparative economic screenings, the following specific

supply alternatives were modeled in Plexos® for each designated duty cycle:

• Peaking capacity was modeled as blocks of seven, 86 MW GE-7EA

Combustion Turbine units (summer rating of 78.5 MW x 7 = 550 MW),

available beginning in 2017. Note: No more than one block could be selected

by the model per year.

• Intermediate capacity was modeled as single natural gas Combined Cycle (2 x

1 GE-7FA with duct firing platform) units, each rated 618 MW (562 MW

summer) available beginning in 2017.

Note: In addition to the results of the comparative economic screening, due to

the lack of significant resource need as well as the largely prohibitive cost and

attendant construction risk, traditional baseload resources, as previously

defined, were not considered in this modeling.

In addition, beginning in the year 2020:

• Wind resources were made available up to 100 MW annually of incremental

nameplate capacity.

• Utility-scale solar resources were available up to 10 MW annually of

incremental nameplate capacity.

• DG, in the form of distributed solar resources, was limited to approximately

2.5% of energy consumption by 2028.

• EE resources—incremental to those included in the load forecast—were

limited to realistically achievable levels in each year.

4.6.4 Wind RFI Evaluation and Assumptions

AEPSC on behalf of the Company issued a RFI on October 18, 2013 for non-

binding indicative responses for a 100 MW (nameplate) power purchase agreement. The

RFI was seeking responses from PJM wind resources (operating or planned) that could

deliver energy, capacity, and renewable energy credits for a 20-year term starting on

January 1, 2017; January 1, 2018; or another start date as described by the entity

responding to the RFI. Responses to the RFI were received by AEPSC on November 15,

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KENTUCKY m°1 POWER


2013. A total of twelve developers provided responses representing 25 projects totaling

2,450 MW of PJM wind resources. Of the 2,450 MW of PJM wind resources, 2,280

MW were in the developmental stage. The remaining —170 MW of projects are currently

in service. All responses to the RFI were from PJM resources representing nine states

(IN, IL, KY, MD, NC, OH, PA, VA, WV).

4.6.5 Commodity Pricing Scenarios

Five commodity pricing scenarios were developed by AEPSC for Kentucky

Power to enable Plexos® to construct resource plans under various long-term pricing

conditions. The long-term power sector suite of commodity forecasts are derived from

the proprietary AuroraxmP. AuroraxmP is a long-term fundamental production-costing

tool developed by EPIS, Inc., that is driven by user-defined input parameters, not

necessarily past performance which many modeling techniques tend to utilize. For

instance, unit-specific fuel delivery and emission forecasts established by AEP Fuel,

Emissions and Logistics (FEL), are fed into AuroraxmP. Likewise, capital costs and

performance parameters for various new-build generating options, by duty-type, are

vetted through AEP Engineering Services and incorporated in the tool. AEP uses

AuroraxmP to model the eastern synchronous interconnect as well as ERCOT. In this

report, the three distinct long-term commodity pricing scenarios that were developed for

Plexos® are: a "base" view or, "Fleet Transition 1H2013 Base," a plausible "Fleet

Transition 1H2013 Lower Band," and a plausible "Fleet Transition 1H2013 Higher

Band." The scenarios are described below with the results shown in Figure 19.

a. Fleet Transition 1H2013 Base

This case recognizes the vacatur of CSAPR by decision of the U.S. Court of

Appeals. Consequently, certain emission allowance values prior to 2015 revert back to

levels in line with continued administration of the Clean Air Interstate Rule pending the

promulgation of a valid replacement. Assumptions include:

• MATS Rule effective date as proposed with compliance beginning in 2015;

• Initially lower natural gas price due to the emergence of shale gas plays; and

• CO-) emission pricing begins in 2022.

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The specific effect of the MATS Rule are modeled in the development of the

long-term commodity forecast by retiring the smaller, older coal units which would not

be economic to retrofit with emission control equipment. The retirement time frame

modeled is 2015 through 2017. Those remaining coal generating units will have some

combination of controls necessary to comply with the EPA's rules. Incremental regional

capacity and reserve requirements will largely be addressed with new natural gas plants.

One effect of the expected retirements or the emission control retrofit scenario, is an

over-compliance of the previous CSAPR emission limits. This will drive the emission

allowance price to zero by 2018 or 2019.

b. Fleet Transition 1H2013 Lower Band

This case is best viewed as a plausible lower natural gas/energy price profile

compared to the Fleet Transition 1H2013 Base. In the near term, Lower Band natural gas

prices largely track the Base Case but, in the longer term, natural gas prices represent an

even more significant infusion of shale gas. From a statistical perspective, this long-term

pricing scenario is approximately one (negative) standard deviation from the Base Case

and illustrates the effects of coal-to-gas substitution at plausibly lower gas prices. Like

the Base Case scenario, CO2 mitigation/pricing is assumed to start in 2022.

c. Fleet Transition 1H2013 Higher Band

Alternatively, this Higher Band scenario offers a plausible, higher natural

gas/energy price "sensitivity" to the Base Case scenario. Higher Band natural gas prices

reflect certain impediments to shale gas developments including stalled technological

advances (drilling and completion techniques) and as yet unseen environmental costs.

The pace of environmental regulation implementation is in line with Fleet Transition and

Lower Band. Analogous to the Lower Band scenario, this Higher Band view, from a

statistical perspective, is approximately, one (positive) standard deviation from the Base

Case. Also, like the Base Case and Lower Band scenarios, CO) pricing is assumed to

begin in 2022.

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d. High CO2

Built upon the assumption of a $25 per tonne CO) mitigation price beginning in

2022, the High CO, Scenario includes correlative price adjustments to natural gas and

coal due to changes in consumption. This results in some retirement of coal-fired

generating units around the implementation period. Natural gas and, to a lesser degree,

renewable generation is built as replacement capacity.

e. No-CO2

This "business as usual" scenario also includes the necessary correlative fuel

price adjustments and best serves as a baseline to understand the market impact of the

Fleet Transition 1H2013 Base Case and the High CO, Scenario. All three commodity

pricing scenarios assume the same input parameters but for fuels and CO2 mitigation

pricing.

Figure 19: Commodity Prices

Power On-Peak AEP-PJM Hub Price (2011$/MWh) 70.0

60.0

50.0

40.0

30.0

20.0

10.0

0.0 2014 2016 2018 2020 2022

2024 2026

2028

Base Lower band Higher Band —No CO2 —High CO2

Power Off-Peak AEP-PJM Hub Price (2011$/MWh) 50.0

10.0

0.0

2014 2016 2018 2020 2022 2024 2026 2028

Base — Lower band Higher Band — No CO2 — - High CO2

156

5.0

4.0

3.0

2.0

1.0

0.0

KENTUCKY POWER

A unit of American Electric' Power


CO2 Price (2011$/tonne)

25.0

20.0

15.0 1

10.0

5.0

0.0

2014 2016 2018 2020 2022

2024 2026 2028

Base Lower band Higher Band No CO2 — High CO2

Natural Gas (TCO Delivered) Price (2011$/mmBtu)

2014 2016 2018 2020 2022 2024 2026 2028

Base Lower band Higher Band — No CO2 — High CO2

Natural Gas (TCO Pool) Price (2011$/mmBtu) 7.0

6.0

5.0

4.0

3.0

2.0

1.0

0.0

2014 2016 2018 2020 2022 2024 2026 2028

Base Lower band Higher Band — No CO2 — — High CO2

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16.0

14.0

12.0

10.0

8.0

6.0

4.0

2.0 -

Coal (ILB) Price (2011$/ton) 70.0

60.0

50.0

40.0

30.0

20.0

10.0

0.0

2014 2016 2018 2020 2022 2024 2026 2028

Base -- — Lower band 44— Higher Band — No CO2 — — High CO2

Coal (PRB 8800) Price (2011$/ton)

0.0

2014 2016 2018 2020 2022 2024 2026 2028

Base Lower band —4— Higher Band — —No CO2 High CO2

Capacity (AEP Gen Hub) Price (2011$/MW-day) 300.0

250.0

200.0

150.0 -

100.0

50.0

2014 2016 2018 2020 2022 2024 2026 2028

--Base --- Lower band —4— Higher Band —No CO2 - -High CO2

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A unit of American Eleatic Power 2013 Integrated Resource Plan

4.7 Modeling Results

Plexos® constructed an optimized portfolio for each of the economic scenarios. A

summary of the (nameplate MW) resource additions in each of the optimized plans is

shown in Table 18 below.

Table 18: Optimized Plans Summary Additions (2014-2028)

MW- nameplate Wind Solar Efficiency

Total

Additions

Base 100 90 25 215

Low 80 25 105

High 100 90 25 215

No Carbon 80 25 105

High Carbon 100 90 25 215

Although Kentucky Power has sufficient capacity to satisfy its PJM summer

reserve margin criterion, Plexos® will consider the continued addition of resources that

are economic; that is, resources that would offer value vis-à-vis the Company's avoided

costs.

Stated another way, although Kentucky Power has sufficient capacity to satisfy its

PJM summer capacity criterion, Plexos0 will continue to add resources that are

economic based on the inherent energy contribution. These resources would serve to

reduce Kentucky Power's generation/production-related revenue requirement over the

long-term. So, even though Kentucky Power has adequate capacity to serve its summer

peak requirement without the addition of incremental resources through the planning

period, since Kentucky Power's customers use significant amounts of energy, particularly

during the winter, the failure to consider the addition of these resources would result in

Kentucky Power's customers having greater exposure to PJM energy markets. This is

also true if, or when, a "cost" for CO? emissions is effected as the Mitchell and Rockport

coal units, as modeled, would be expected to run less often at that point. To summarize,

Plexos® may add additional resources because it may produce energy at a cheaper cost

than is expected in the (energy) replacement markets.

159

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■ Fossil ■ Efficiency ■ Wind ■ Solar E Market Purchases Forecast

9000

8000

7000

6000

5000

4000

3000

2000

1000

0

E

9000

8000

7000

6000

5000 to

73 4000

3000

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2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028

■ Fossil ■ Efficiency ■ Solar ■ Wind ci Biomass W Market Purchases Forecast

KENTUCKY POWER'



This energy position exposure is evidenced by the following two charts, first,

under Base Commodity pricing (See Figure 20) and then under High CO,) pricing

(Figure 21). In sum, the addition of these non-traditional resources would then serve as a

hedge to reduce exposure to (PJM) energy markets, which may be particularly desirable,

depending on CO2 costs.

Figure 20: Kentucky Power Energy Position under Base Commodity Forecast

Figure 21: Kentucky Power Energy Position under High CO2 Commodity Forecast

160

ENTUCKY ER


4.7.1 Construction of the Preferred Portfolio

Optimization under the five economic scenarios yielded five unique resource

portfolios. Because much of Kentucky Power's resource portfolio is already in place, the

differentiation that such different economic scenarios provded was somewhat muted.

However, that result in itself, is valuable information in that it helps to solidify the path

forward.

One missing element of all of the resultant portfolios is distributed generation, in

particular, distributed solar generation. This resource is not selected primarily because of

the way current net metering credits are determined. In essence, credits are given for the

full retail cost of electricity, while the system benefits primarily from the energy and

generation capacity benefits. Distributed solar produces its peak energy at approximately

1 p.m. on a typical day, while the PJM system peaks at (approximately) 5 p.m. Figure 22

shows the relationship between expected solar costs and their value to the utility. The

chart shows two things: First, with declining solar costs and current net metering rules,

Kentucky Power DG consumers can potentially expect distributed solar power to become

a cost-effective resource within five years. Second, under the same net metering

compensation rules, these same resources are not economical additions from a (utility-

based) revenue requirements perspective in that it would be less expensive to pay the

avoided (PJM) market cost for capacity and energy as opposed to the net metering tariff.

161

Consumer break-even under full-retail net metering

t 1.50

Utility break-even

-relative to RO-

value

Net metering credit in excess of PJM value; net-metered solar not

economically selected

PIM Value of 5olar

Net Metering Payments Utility Scale PV with ITC

— Consumer Scale PV with ITC

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

faTi KENTUCKY PO ER A unit of American Electric Power


Figure 22: Relationship between Expected Solar Costs and Utility value

The excess cost of net metering has been argued, by solar power advocates, to be

fair compensation for off-setting other grid investments, including transmission and

distribution additions. However, there is limited utility evidence to support that claim

given the winter peaking nature of Kentucky Power. There is virtually no solar

production at the hour of Kentucky Power's (winter) peak (typically a winter weekday

morning) which nullifies that argument for Kentucky Power as shown in Figure 23.

162

Kentucky Demand ----Solar Output

100% -

90% —

80% - —

70%

60%

50%

40%

30%

20%

10%

0% L 1 2 3 4 5 6 7 8 9 10 11 12

Month

KENTUCKY /ER


Figure 23: Solar Production vs. Demand of Kentucky Power

However, the Preferred Portfolio recognizes that adoption of customer-sited

generation, particularly solar panels, is likely given the net-metering economics. It is

uncertain how quickly net metering will be adopted by customers. Currently, the net-

metered capacity on Kentucky Power's system consists of 3 commercial customers

totaling only 38 kW15. Given Kentucky Power's relatively low rates and depressed

economic footprint, rapid adoption prior to 2020 is not likely. Thus, a nominal amount of

distributed solar is added to the Preferred Portfolio in 2016, just prior to the reduction in

the federal investment tax credit (ITC) from 30% to 10%and continuing at a reduced rate

(Figure 24).

15 EIA 826 data current as of 10/31/2013.

163

KENTUCKY ER


30

2 25

co"

tr)

a,

L

20

15

10


Figure 24: Preferred Portfolio Distributed Solar Adoption Assumption

75

y3 yo o o ,yo ,yo o 619 61> e 61,'N e e 0,A e e The optimium portfolios did not add EE in quantities sufficient to comply with

the Mitchell Transfer Stipulation and Settlement Agreement. It must be recognized,

however, that there are limitations to the precision of using program costs and (adjusted)

impacts from one state (Vermont) in another state (Kentucky). Ultimately, the costs and

impacts of the incremental programs will be known and approval for those programs will

be through the prescribed channels of the appropriate DSM Collaborative and ultimately

the Commission. Thus, the Preferred Portfolio includes energy efficiency resources in

amounts approximate to the those in the Agreement.

4.7.2 Preferred Portfolio summary

The Preferred Portfolio is largely based upon the Plexos® model-optimized

portfolio, established under 'Base' long-term commodity pricing forecast, that imparts

some practical considerations.

First, it defers a currently-developed wind investment that takes advantage

of the wind PTC until 2015 providing allowance for the time necessary for

necessary additional analysis and regulatory approval.

164

Evil PUCE ER


Second, a nominal amount of customer-owned, net-metered distributed

solar is included. While not an optimal resource from the perspective of

the utility in aggregate, given the economics from the perspective of

individual customers under current net metering provisions, it is

reasonable to expect some level of adoption of this resource by Kentucky

Power customers.

Third, additional customer-based EE programs were added to meet the

terms of the Mitchell Transfer Stipulation and Settlement Agreement.

With that, the later tranches of model-optimized VVO were set aside to

accommodate these additional programs.

Table 19 offers a high-level summary of the Preferred Portfolio capacity resource

(nameplate MW) additions over the 2014-2028 planning period, compared to the five

model-optimized set of additions, by pricing scenario.

Table 19: Preferred Portfolio, Summary Additions (2014-2028)

MW- nameplate Wind Solar Efficiency

Total

Additions

Base 100 90 25 215

Low - 80 25 105

High 100 90 25 215

No Carbon - 80 25 105

High Carbon 100 90 25 215

Preferred Plan 100 132 31 263

Through 2028, the Preferred Portfolio results in approximately $29 million in

incremental costs over the cost-optimized Base portfolio or a difference of approximately

0.050/kWh. These incremental costs are primarily the result of the assumption of non-

economic (under current net metering rules) distributed resource additions, which may or

may not materialize.

Table 20 shows the P/exos it -based output summary of the differences in present

value of the Preferred Portfolio and the plan that results from a pure model optimization

under the Base pricing economic scenario.

165

BASE Pricing:

Preferred Plan

Plan Scenarios:

Kentucky Power Company

2013 IRP

Plexos ® Long-Term Economic Analysis

SUMMARY Cumulative Present Worth (CPW) of Generation Revenue Requirements - Preferred Plan vs. Optimized Plan

(2014$)

IRP (15-Yr) Study Period:

2014-2028

Change

vs.

CPW "BASE Optimized"

$M $/14

2,442 29 1.2%

Optimized Plan 2,414

Total Study Period vv/ 'End-Effects':

2014-2040

Change

vs.

CPW "BASE Optimized"

$M $A4

4,186 74 1.8%

4,112

al; KENTUCKY mmo POWER

A unit ofAmerican Electric Rawer 2013 Integrated Resource Plan

Table 20: Long-Term Economic Summary

4. 8 Risk Analysis

In addition to evaluating the Preferred Portfolio for its ability to perform under

the universe of likely economic backdrops, a portfolio that consisted of the "fossil-only"

assets and the ecoPower facility was also evaluated to isolate the impacts associated with

the incremental assets added in the Preferred Plan.

The two portfolios were evaluated using a Monte Carlo technique where input

variables are randomly selected from a universe of possible values, given certain

constraints and relationships. This offers an additional approach by which to "test" these

plans over a distributed range of certain key variables. The output is, in turn, a

distribution of possible outcomes, providing insight as to the risk or probability of a high

CPW relative to the expected outcome.

This study focused solely on the Kentucky Power portfolio of generating units.

One-hundred risk iteration runs were performed with four risk factors being sampled. The

results take the form of a distribution of possible revenue requirement outcomes for each

plan. Table 21 shows the input variables or risk factors within this IRP analysis and their

historical relationships to each other.

166

KENTUCKY POWER'



Table 21: Risk Factors and their Relationships

Natur

Gasal Coal

P

Pric

ower

es Demand

Natural Gas 1 0.18 0.47 0.08 Coal 1 0.53 -0.29 Power Prices 1 -0.19 Demand 1

The variables inputs, and their range of possible (nominal) values over those 100

iterations are shown in Figure 25.

Figure 25: Variable Input Ranges

167

78

76

74

72

70

68

66

64

62

60

120

Power Prices 100

80

a 60

40

20

0 2014 > 2040

KENTUCKY POWER'



4.8.1 Modeling Process & Results & Sensitivity Analysis

(170 IAC 4-7-8(10)(B))

For each portfolio, the difference between its median and 95th percentile was

identified as Revenue Requirement at Risk (RRaR). The 95111 percentile is a level of

required revenue sufficiently high that it will be exceeded, assuming the given plan is

adopted, in five of the one-hundred simulations. Thus, it is 95% likely that those higher-

end of revenue requirements would not be exceeded. The larger the RRaR, the greater the

level of risk that customers would be subjected to adverse outcomes relative to the Base

Case CPW.

Figure 25 illustrates the RRaR and the expected value graphically.

168

Figure 26: RRaR and Expected Value

Fossil+ecoPower Preferred

$1,030 RRaR

$905

ENTUCKY ER



4,175 4,400 4,625 4,850 5,075 5,300 5,525 5,750 5,975 6,200 6,425 6,650

CPW ($millions)

The differences in RRaR between the portfolios do not appear to be significant.

However, the addition of EE and solar generation, both distributed and utility-scale, work

to reduce the risk or revenue requirement volatility. This is apparent by the reduction in

RRaR associated with the Preferred Portfolio relative to the fossil-only portfolio.

Based on the risk modeling performed, it is reasonable to conclude that the

Preferred Portfolio represents a reasonable combination of expected costs and risk

relative to the cost-risk profiles of a portfolio with more significant energy market

exposure.

4.8.2 Sensitivity to CO2 Pricing

To determine the cost of a CO? requirement on Kentucky Power, the optimum

modeled portfolios for the "Base", "No CO?" and "High CO?" pricing scenarios are

compared. The cost to Kentucky Power customers associated with the impacts of

169

ENTUCKY ER

A unit ofAmerican Electric Power

$160,000

$140,000

2 $120,000 -1

$100,000 cr LI) $80,000 a) 2 $60,000 a)

ig $40,000

t $20,000

$0

-$20,000

Base High CO2


incorporating a carbon cost/price is expected to be $525 million in present value,

measured from 2014-2040 (or approximately 1.10/kWh beginning in 2022), when

considering the carbon pricing already inherent in the "Base" pricing scenario. The bulk

of the additional costs begin in 2022, the assumed start date of a carbon tax, with some

costs beginning sooner as cost reduction strategies are implemented.

In the event the High CO2 pricing scenario is realized, that additional cost

increases to $834 million in present value (approximately 1.80/kWh beginning in 2022).

Figure 27 shows the increased annual (nominal) revenue requirements of the expected

Base case and High CO2 case relative versus a modeled case with no cost for CO,) (No

CO,) pricing scenario).

Figure 27: Annual Impacts of CO2 Costs on Revenue Requirements

4.9 Kentucky Power Current Plan

The optimization results and associated risk modeling of this IRP show that, for

Kentucky Power as a stand-alone entity in the PJM RTO, the addition of wind, solar, and

customer and grid energy efficiency resources serve to reduce overall costs. The

Preferred Portfolio results in reasonable costs when compared to other portfolios while

reflecting a level of distributed (solar) generation that is reasonable to expect will

170

KENTUCKY ER


emerge under current cost assumptions and net metering arrangements. The following

are summary highlights of the Preferred Portfolio.

• Receives 50% of the Mitchell Plant in 2014.

O Retires Big Sandy Unit 2 in 2015.

• Converts Big Sandy Unit 1 to natural gas fired operation in 2016.

• Assumes the potential addition of 100 MW of wind energy from a PTC eligible wind

project beginning in 2015.

® Implements customer and grid EE programs so as to reduce energy requirements by

260 GW1-1 (or 4% of projected energy needs) by 2028.

• Purchases the output of the 58.5 MW ecoPower facility beginning in 2017.

• Adds utility-scale solar beginning in 2020; total solar capacity reaches 90 MW

(nameplate) in 2028.

• Recognizes additional solar capacity will be added by customers, starting in 2016, of

about 3 MW (nameplate) and ramping up to about 41 MW (nameplate) by 2028.

4.10 IRP Summary

Inasmuch as there are many assumptions, each with its own degree of uncertainty,

which had to be made in carrying out the resource evaluations, changes in these

assumptions could result in modifications in the resource plan reflected for Kentucky

Power. The resource plan presented in this IRP is sufficiently flexible to accommodate

possible changes in key parameters, including load growth, environmental compliance

assumptions, fuel costs, and construction cost estimates. As such, changes and

assumptions are recognized, updated, and refined, with input information reevaluated and

resource plans modified as appropriate.

171

ENTUCKY ER



This 2013 Kentucky Power IRP provides for reliable electric utility service, at

reasonable cost, through a combination of existing resources, renewable energy and

demand-side programs. Kentucky Power will provide for adequate capacity and energy

resources to serve its customers' peak demand, energy requirement and required PJM

reserve margin needs throughout the forecast period.

4.11 KPSC Staff Issues Addressed

On March 4, 2011, the Commission issued their Staff's report on Kentucky

Power's 2009 IRP and requested that the Company address certain issues in its next IRP

report (this report). The following recommendations pertaining to Supply-Side Resource

Assessment are restated from the Staff report and addressed below:

Kentucky Power should identify the resources available to it as both a member of the AEP-East Power Pool and as a stand-alone utility. Kentucky Power should also include a detailed discussion of the then-current status of the AEP-East Power Pool, any changes or-modifications that are under consideration, and the potential impacts to Kentucky Power.

Please see Exhibit 4-9 (in the Confidential Supplement to this filing) for a list and primary characteristics of capacity options screened. The list has been expanded and new options will be added as they become available. Also, see section 4.2.3 for discussion of the existing pool and bulk power arrangements. In sum, the elimination of the AEP Pool Agreement naturally results in Kentucky Power's resource planning being performed exclusively on a "stand-alone" basis.

2. Kentucky Power should provide a specific discussion on the consideration given to renewable generation by Kentucky Power.

Please see section 4.3.4.5.

3. Kentucky Power should discuss the existence of any cogeneration within its service territory and the consideration given to cogeneration in the resource plan.

Please see section 4.3.4.5.e.

172



4. Kentucky Power should specifically identify and describe the net metering equipment and systems installed. A detailed discussion of the manner in which such resources are considered in its IRP should also be provided.

Please see sections 4.3.5.2 and 4.7.1.

5. Kentucky Power should provide a detailed discussion of the consideration given to distributed generation

Please see sections 4.3.5.2, 3.5.1.5 and 3.5.1.6.

6. Kentucky Power should provide a specific discussion of the improvements and more efficient utilization of transmission and distribution facilities as required by 807 KAR, Section 8 (2)(a). This information should be provided for the past three years and should address Kentucky Power's plans for the next three years.

Please see section 4.4.1.

7. In addition to describing how Kentucky Power has addressed currently pending environmental regulations and perhaps new legislation, describe how Kentucky Power has specifically addressed such legislation. The next IRP should also address the expected impact on Kentucky Power of any then-potential environmental regulation or legislation.

Please see sections 4.2.4 and 4.7.

173

PJM Zone Allegheny Power

am American Electric Power Co., Inc.

11111 Atlantic City Electric Company

Baltimore Gas and Electric Company

IN Commonwealth Edison Company

Delmarva Power and Light Company

11111 Duquesne Light Company

11111 Jersey Central Power and Light Company 1111

Metropolitan Edison Company

PECO Energy Company

PPL Electric Utilities Corporation

Pennsylvania Electric Company

Potomac Electric Power Company

Public Service Electric and Gas Company

Rockland Electric Company

The Dayton Power and Light Co.

Virginia Electric and Power Co.

Legend

INN

Z. KENTUCKY POWER


4.12 Chapter 4 Exhibits

Exhibit 4-1


174

KENTUCKY POWER



Exhibit 4-2 (807 KAR 5:058 Sec.8.3.b.1-10.)

Kentucky Power Existing Generation Capacity as of December 2013

Plant Fuel AEP Winter Summer Storage SCR FGD

In-Service Own/ Mode of Capability Capability Fuel Capacity Installation Installatio Super Plant Name Location Unit No. Date Contract Operation (MW) (MW) Type (Tons 000) Year n Year Critical Age

Big Sandy Louisa, KY 1 1963 0 Base 278 278 Coal 1,750 — -- N 50 Big Sandy — r 2 1969 0 Base 800 800 Coal — 2,004 2,015 Y 44 Rockport Rockport, IN 1 1984 0 Base 198 198 Coal — 2,017 2,017 Y 29 Rockport — 2 1989 C Base 195 195 Coal — 2,019 2,019 Y 24

Kentucky Power Coal 1,471 1,471 40

I otal Kentucky Power 1,4 /1 1,4/1 40

175



Exhibit 4-3 (807 KAR 5:058 Sec.8.3.b.12.c and e.)

Kentucky Power STEAM GENERATING-CAPACITY COST INFORMATION

2012 Average Average

Non-Fuel Variable Total

Average Variable Fixed Production Production

Plant Fuel Cost O&M O&M Cost Cost

Name (a) (c/Mbtu) ($000) ($000) (c/kWh) (c/kWh)

Big Sandy 321.61 5,100 15,738 3.72 4.10

Mitchell 291.78 16,489 40,837 3.20 3.64

Rockport 221.40 13,786 180,073 3.06 3.20

Notes:

(a) Mitchell and Rockport data represent total plant capacities

176

KENTUCKY POWER



Confidential Exhibit 4-4 (page 1) (807 KAR 5:058 Sec.8.3.b.12.c.)

See Confidential Exhibit 4-4, the "Kentucky Power, Projected Average Variable Production Costs (2014-2028)" provided in the Confidential Supplement to this filing.

(Page 1 of 3) REDACTED

KENTUCKY POWER COMPANY STEAM GENERATING CAPACITY

Projected Average Fuel Costs (¢/MMBtu) (2014 - 2028)

Unit

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Big Sandy 1 Big Sandy 2 Mitchell 1 Mitchell 2 Rockport 1 Rockport 2 BS1STGAS 1

177

KENTUCKY .POWER A unit of American Electric Power


Confidential Exhibit 4-4 (page 2) (807 KAR 5:058 Sec.8.3.b.12.g.)

See Confidential Exhibit 4-4, the "AEP System-East Zone, Projected Average Variable Production Costs (2014-2028)" provided in the Confidential Supplement to this filing.



Projected Average Variable Production Costs (0/kWh) (2014 - 2028)

Unit


178



Confidential Exhibit 4-4 (page 3) (807 KAR 5:058 Sec.8.3.b.12.e.)

See Confidential Exhibit 4-4, the "Kentucky Power, Projected Non-Fuel Variable O&M (2014-2028)" provided in the Confidential Supplement to this filing.



Projected Non-Fuel Variable O&M ($000)

(2014 - 2028)

Unit 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 Big Sandy 1 Big Sandy 2 Mitchell 1 Mitchell 2 Rockport 1 Rockport 2 BS1STGAS 1

179



Exhibit 4-5

(807 KAR 5:058 Sec.8.3.b.12.a. and b.)

Kentucky Power STEAM GENERATING-CAPACITY OPERATING INFORMATION

2012

Plant Name

Unit

Number

Capacity

Factor (%)

Equivalent

Availability

Factor (%)

Average

Heat

Rate

(Btu/kWh)

Big Sandy 1 30.28 60.26 10,441

2 27.35 47.84 10,113

Mitchell 1 59.96 75.42 10,360

2 50.27 64.65 9,638

Rockport 1 82.86 89.37 9,674

2 80.33 87.15 9,881

180

gin4 KENTUCKY ER


Confidential Exhibit 4-6 (page 1) (807 KAR 5:058 Sec.8.3.b.12.a.)

See Confidential Exhibit 4-6, Kentucky Power, Projected Operating Information provided in the Confidential Supplement to this filing.


KENTUCKY POWER COMPANY STEAM GENERATING CAPACITY Projected Capacity Factors (%)

(2014 - 2028)

Unit


181

ICENI KY POW A unit ot American Electric Power


Confidential Exhibit 4-6 (page 2) (807 KAR 5:058 Sec.8.3.b.12.a.)




Projected Equivalent Availability Factors (%) (2014 - 2028)

Unit


182

Lillie' KENTUCKY POWER

A unit ofAmerican Electric Power 2013 Integrated Resource Plan

Confidential Exhibit 4-6 (page 3) (807 KAR 5:058 Sec.8.3.b.12.b.)




Projected Average Heat Rates (Btu/kWh) (2014 - 2028)

Unit


ntsummev

183

P A unit of American Electric Power 2013 Integrated Resource Plan

Exhibit 4-7 Going-In PJM View

KENTUCKY POWER COMPANY Projected Summer Peak Demands, Generating Capabilities, and Margins (UCAP)

Based on (July 2013) Load Forecast (2012/2013 - 2030/2031)

2013 (Going-(n)

(1) (2) (3) (4)

(5) (6) ( 7) (8)

(9) (10) (11) (12)

(13) (14) (15) (16) (17) (18)

(19) (20)

0)1)0(3)

v)(41- .(8)0(0)

k(11)412)

=(16)11- v11111-(12) .(150)10) «57(6»)'(

Sum(14)

(17))

*(15)1.0- 7)

'0(15)

(17)1 -(10)

Obligation to PJM Resources KPCo Position (MW) Planning

Year Internal DSM (la) Projected Net Interruptible Dullard Forecast UCAP Net UCAP Total

Demand DSM Internal Demand Response PoolReq't Obligation Market UCAP (a) Impact (c) Demand Response Factor (e) Obligation Obligation

(d) (I)

Ex:stir-9 Net Annual Net ICAP AEP Available Capacity Capacity Purchases EFORd 9) UCAP

& Planned Sales (h) Changes Planned Capacity Additions

Net Position Net Position wlo New a New Capacity Capacity

(5) Unrts MW (i) 2012 /13 2013 /14 2014 /15 2015 /16 2016 (17

(6) 1,167 00 1,136 (k) 1,157 (k) 1,180 (19 1,198

(3) (3) (5) (7) (9)

(1) (1) (1) (2) (3)

1,166 1,135 1,156 1,178 1,196

0 0 0 0 0

0.954 0.957 0956 0.958 0.955

1.087 1 089 1.089 1.085 1090

1,267 1,236 1,259 1,278 1,304

0 0 0 0 0

1267 1,235 1,259 1,278 1,304

1,470 1,470 2250 1,432 1,432 1,432 1,438 1,438 1,443 1,443 1.443 1,443 1,443 1,440 1,440 1,440 1,438

67 50 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

1,403 1,420 2,250 1,432 1,432 1,432 1,438 1,438 1,443 1,443 1,443 1.443 1,443 1,440 1,440 1,440 1,438

7,55% 465%

20.77% 8.09% 743% 743% 7,42% 7.42% 742% 742% 7.42% 7.42% 742% 7.42% 7.42% 7.42% 742%

1,293 1,354 1,783 1,316 1,326 1,326 1.331 1,331 1,336 1.336 1,336 1,336 1,336 1,333 1,333 1,333 1,331

26 118 524 38 22 167 171 170 174 169 164 162 161 151 147 141 136

26 118 524 38 22 167 171 170 174 169 164 162 161 151 147 141 136

2017 /18 2018 /19 2019 /20 2020 /21 2021 (22 2022 123 2023 24 2024 25 2025 /26 2026 /27 2027 /28 2028 /29

1,066 1,069 1,072 1,074 1,081 1,086 1,088 1,090 1,097 1,102 1,107 1,109

(10) (11) (12) (12) (13) (13) (14) (14) (14) (14) (14) (14)

(3) (5)

(7) (9)

(10) (11) (12) (12) (13) (13) (14) (14)

1,063 1,064 1065 1,065 1,071 1,075 1,077 1,078 1,084 1,088 1,093 1,096

0 0 0 0 0 0 0 0 0 0 0 0

0.955 0.955 0.955 5.955 0.955 0.955 0.955 0.955 0.955 0.955 0.955 0 955

1.090 1.090 1.090 1.090 1090 1.090 1.090 1.090 1.090 1.090 1.090 1.090

1,159 1,160 1,161 1,162 1,167 1,172 1,174 1,175 1,182 1,186 1,192 1 195

0 0 0 0 0 0 0 0 0 6 0 0

1,159 1,165 1.161 1,162 1,167 1,172 1,174 1,175 1,182 1,186 1,192 1,195

Notes: (a) 'Based an (July 2013) Load Forecast (with implied PJM diversity factor)

(b) Existing plus approved and projected "Passive" EE, and VVO (note: these values & timing are for reference oNy and are not reflected in position determination)

(c) For PJM planning purposes, the ultimate impact of new DSM is 'delayed' -4 years to represent the ultimate recognition of these amounts through the PJM-originated load forecast process

(d) Demand Response approved by PJM in the prior planning year plus forecasted "Active" DR

(e) Installed Reserve Margin (IRM). 15.6%(2012), 15.9%(2013-2014), 15.3%(2015), 15.6%(2016-2030) Forecast Pool Requirement (FPR) = (1a IRM)' (1 - PJM EFORd)

(f) Includes company MLR share of FRR viewer obligations only

(5) Reflects the members ownership ratio of folievAng summer capability assumptions: Wind Farm PPAs (Where Applicable(

(9) continued EFFICIENCY IMPROVEMENTS:

2018/19: Rockport 1: 36 MW (turbine) 2020/21: Rockport 2: 36 MW (turbine)

EGO DERATES: 2025/26: Rockport 1:18 MW 2028/29: Rockport 2:18 MW

OSI DERATESt 2014/15: Rockport 1-2: 0 MW each

GAS CONVERSION REBATES: 2016/17 Big Sandy 1: (18) MW

RETIREMENTS: 2015/16: Big Sandy 2 2025/26: Big Sandy 1

(h) Includes companys share of Ceredo/Darby/Glen Lyn Sale to AMPO,ATSI, and IMEA 2012/13 (171 MW) Sale of 12 MW in 2012/13 and 13 MW in 2013/14 to Duke Sale of 210 MW 2012/13 to EMMT RPM Auction Sales 2012/13 -2013/14 (646, 700)(MW UCAP)

3.6 MW capacity credit from SEPA's Philpot Darn via Blue Ridge contract

Plus: Estimated l&M nominations for PJM EE ('passive' DR program) levels -reflected as a UCAP '<resource,- as part of PJM's emerging auction products (elf: 2014/15)

(I) Newwind and solar capacity value is assumed to be 13% and 38% of 'lament.;

(j) Beginning 2008/09, based on 12-month avg. AEP EFORd in eCapacity as of twelve months ended 9130 of the preview year

(k) Actual PJM forecast

('I Combustion Turbines (CT) added to maintain Black Start capability

Effective 1-1-2014, remaining capacity that was previously MLR'd will be allocated as follows:

1) SEPA -4> 100% to APCo

184

KENTUCKY ER


Exhibit 4-8 Going-In Kentucky Power Winter

KENTUCKY POWER COMPANY Projected Winter Peak Demands, Generating Capabilities, and Margins (ICAP)

Based on (July 2013) Load Forecast

(2012/2013 - 2028/2029) 2013 (GoIng-In)

12) (3) (4) (5)

eSurn(1-9)

(0) (7)

-9Surr(5-5)

(6) (0 ) (10) (11) (12) (13)

=00)06 +5um/11)0(12)

(14) (15) (16) (17)

=(13)-(5) 0(14)857100 n(13)-(7) =(16x7r100

Peak Demand - MW Winter Season

Internal Internal DSM (b) Committed Net Demand Interruptible Total Demand (a) Wholesale Sales (0) Demand Demand

Contracts

2011/12 Actual 1,378 0 1,378 1,378 2012/13 Actual 1,409 0 1,909 1409 2013/14 1,440 (8 ) 1,432 1,432 2014/15 1,442 (11) 1,431 1..131 2015/16 1,445 (13) 1,432 1 4 -32 2016/17 1,446 (15) 1,431 1,431 2017/18 1,440 (17) 1,431 1,431 2018/19 1,450 (18) 1,432 1,432 2019/20 1,449 (10) 1,430 1,930 2020/21 1,456 (20) 1,436 1,436 2021/22 1,460 121) 1,439 1,439 2022/23 1,459 (21) 1,438 1,938 2023/24 1,459 (21) 1,438 1,436 2024/25 1,985 (21) 1,444 1,444 2025/26 1,469 121) 1,448 1,448 2026/27 1,473 (21) 1,452 1,452 2027/20 1,475 (21) 1,454 1,454 2028/29 1,480 121) 1.459 1,459

Capacity -MW Existing Committed Annual Total Capacity

Capacity 8 Net Sales Purchases Planned (e)

Changes (d) Planned Capacity Additions

Units mi(I)

1,471 9 1,382 1,471 8 1,413 1,471 1 1,430

2,251 2,251 1,433 1,433 1,433 1,433 1,438 1,438 1,438 1,438 1,444 1,444 1,444 1,999 1,444 1,449 1,444 1,444 1,444 1,444 1,944 1,444 1,441 1,441 1,441 1,441 1,441 1,441 1,438 1438

Reserve Margin -MW

Reserve of Internal Reserve % of Internal Margin Demand Margin After Demand Before Interruptible

Interruptible

4 0.30 4 0,30 4 6 30 4 0,30

12) (0.10) (2) (0.10) 820 57.30 620 57,30

1 0.10 1 0.10

2 0.10 2 -0.10 7 (100 7 aso 5 0.40 6 040

14 1.00 14 1.00 a an 8 060 5 6 30 5 0.30 6 6.40 6 0.40 6 0.40 6 0.40 0 0.00 0 0.00

(7) (650) (7) (0.50) (11) (leo) till (0.60) (13) (090) (13) (090)

(21) (1AD) 121) (140)

Notes:

(a)liased on (July 2013) Load Forecast (not coincident with PJM's peak)

(b) Existing plus approved and projected "Passive" EE, and VVO

(c) includes companies MLR share all

(d) Reflects the following Winter capability assumptions:

Wind Farm PPAs (Where Applicable)

EFFICIENCY IMPROVEMENTS:

2017/18: Rockport 1: 35 MVV

2019/20: Rockport 2: 35 MW (turbine)

(d) continued

FGD DERATES:

202526: Rockport 1: 16 MW 2026/29: Rockport 2: 18 MW

DSIDERATES:

2015/16: Rockport 1-2: 0 MW each

GAS CONVERSION RERATES:

2016/17: Big Sandy 1: (18) MW

RETIREMENTS:

2015/16:Sig Sandy 2

2025/26: Big Sandy 1

(e) Includes company's share of.

Contractual share of remaining Mono capacity

Ceredo/Darby/Glen Lyn Sale to AMPO,ATSI. and MEA 2012/13 (171 MW) Sale of 12 MW in 2012/13 and 13 MW in 2013/14 to Duke

Sale 01210 MW 2012/13 to EMMT

RPM Auction Sales 2012/13 - 2013/14 (646, 700)(MW UCAP)

3.6 MW capacity credit from SEPA's Philpot Dam Oa Blue Ridge contract

(I) New wind and solar capacityvalue is assumed to be 13% and 5.57% of nameplate

(1) Combustion Turbines (CT) added to maintain Black Start capability

Effective 1-1)2014, remaining capacity (hat was previously MLR'd will be allocated

as follows:

1) Remaining More Share 4> 10071 to OPCo

2) SEPA => 100% to APCo

Bri

185

Type

Installed

Capability (MW) Cost (d)

Trans. Full Load Fuel Variable

Cost (e) Heat Rate Cost (f) O&M

(916W) (HHV,Btu/kWh) (5/MBtu) (S/MWh)

Fixed Emission Rates

Capacity Overall

Factor Availability

(%) (%)

O&M SO2 (g) NOx CO,

(5/kW-yr) (Lb/mm Btu) (Left m Btu) (Lb/mm Btu) Std. ISO' Winter Sum mer (5/kW)

Base/Intermediate

Combined Cycle (1X1 GE7FA.05) 300 60 0.0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05) 624 60 0.0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05, w/ Duct Firing) 624 60 0.0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05, w/ Duct Firing, Inlet Chillers) 624 60 0.0007 0.009 116.0 60 89.1 Combined Cycle (2X1 GE7FA.05, w/ Duct Firing, Blk Start) 624 60 0.0007 0,009 116.0 60 89.1 Combined Cycle (1X1 SGT6-5000, w/ Evap Coolers) 294 60 0.0007 0.010 116.0 60 89.1 Combined Cycle (2X1 SGT6-5000, w/ Evap Coolers) 609 60 0.0007 0.010 116.0 60 89.1 Combined Cycle (2X1 KA24-2, w/ Evap Coolers) 647 60 0.0007 0.011 116.0 60 89.1 Combined Cycle (2X1 M501GAC, w/ Duct Firing, Inlet Chillers) 780 60 0.0007 0.007 116.0 60 89.1

Peaking

Combustion Turbine (2X1GE7EA) 164 57 0.0007 0.033 116.0 3 93.0 Combustion Turbine (2X1GE7EA,w/ Blk Start) 164 57 0.0007 0.033 116.0 3 93.0 Combustion Turbine (2X1GE7EA, w/ Inlet Chillers) 164 59 0.0007 0.009 116.0 3 93.0 Combustion Turbine (2X1GE7FA.05, w/ Inlet Chillers) 418 59 0.0007 0.007 116.0 3 93.0 Aero-Derivative (1X GE LM6000PF) 45 60 0.0007 0.093 116.0 3 95.0 Aero-Derivative (2X GE LM6000FF) 91 60 0.0007 0.093 116.0 3 95.0 Aero-Derivative (2X GE LM6000PF, w/ Blk Start) 91 60 0.0007 0.093 116.0 3 95.0 Aero-Derivative (1X GE LMS100PB) 98 59 0.0007 0.011 116.0 30 95.0 Aero-Derivative (2X GE LMS100PB, w/ 61k Start) 196 59 0.0007 0.093 116.0 30 95.0 Aero-Derivative (2X GE LMS100PB, v✓/ Inlet Chillers) 196 59 0.0007 0.007 116.0 25 95.0 Wartsila 22 X 20V34SG 201 60 0.0007 0.018 116.0 3 94.0

Notes: (a) Installed cost, capability and heat rate numbers have been rounded.

(b) All costs in 2012 dollars. Assume 1.6% escalation rale for 2012 and beyond.

(c) SAW costs are based on Standard ISO capability.

(d) Total Rant A. Interconnection Cost w/AFUDC (A13.-East rate of 6.12%,site rating 5/kW). (e) Transnission Cost (SAVV,w rAFUDC).

(1) Levelized Fuel Cost (40-Yr. Period 2014-2053)

(g) eased on 4.5 lb. Coal.

(h) Fittsburgh 48 Coal.

1177---7 CICY

.4 unit of American Electric Power 2013 Integrated Resource Plan

Confidential Exhibit 4-9 (807 KAR 5:058 Sec.8.3.b.12.d.)

See Confidential Exhibit 4-9, KPCo, New Generation Technologies provided in the Confidential Supplement to this filing.

AEP SYSTEM-EAST ZONE New Generation Technologies

Key Supply-Side Resource Option Assumptions (a)(b)(c) REDACTED

q111010111N-CCAOS

186

ENTUCKY JER


Due to termination of the AEP Pool and the fact that Kentucky Power is viewed as a

stand-alone company going forward, all AEP-System data have been excluded in this report.

As a result, the following Exhibits provided in the last IRP are no longer

applicable:

Confidential Exhibit 4-10


187

KENTUCKY POWER



Exhibit 4-12 (807 KAR 5:058 Sec.8.3.b.1-11. and Sec. 8.3.c. and Sec. 8.4.a.)

Final CLR PJM View KENTUCKY POWER COMPANY

Projected Summer Peak Demands, Generating Capabilities, and Margins (UCAP)

Based on (July 2013) Load Forecast

(2012/2013 - 2028/2029)

Final

(1) (2) (3) (4) (5)

(6) (7) (8)

(9) (10) (11) (12)

(13) (14) (15) (16) (17) (15) (19) (20)

t.(1)+13)

=15).(9)

.(11)-(12)

11670- =1(11)112) =118)-(10) Sum(14)

(17)) '116)1'(1- 0(15)

(17))910)

Ohl] shun to PJM Planning

Year Internal DSM (b) Projected Net Interruptible Demand Forecast UCAP Net UCAP Total

Demand DSM Internal Demand Response Pool Req't Obligation Market UCAP (a) Impact (c) Demand Response Factor (e) Obkgation Obligation

(0) (t)

Existing Net Capacity Capacity

& Planned Sales (h) Changes

(g) Planned Capacity Additions

Annual Net ICAP AEP Available Purchases EFORd (4 UCAP

Net Position Net Position w/o New w/ New Capacity Capacity

Units MW (1) 2012 /13 (k) 1,167 (3/ (1) 1,166 0 0,954 1.087 1,267 o 1,267 1,470 67 1,403 7.85% 1,293 26 26 2013 /14 (k) 1,136 ( ) (1) 1,135 0 0.957 1.089 1,236 0 1,236 1,470 50 ' 1,420 4,65% 1,354 118 118 2014 /15 (k) 1,157 ( ) (1) 1,156 0 0,956 1.089 1,259 0 1259 2250 0 OSM (5 WV) 7 * 2257 2077% 1,788 524 529 2015 /16 (k) 1,180 (7) (2) 1,178 0 0.958 1.085 1,278 0 1,278 1,432 0 DSM (2 MVV) & 100 W/ Nameplate Wad 16 ' 1,455 8.09% 1,337 38 59 2016 /17 (k) 1,198 (9) (3) 1,196 0 0.955 1 090 1,304 0 1,304 1,432 0 OSM(2 MAI) & 3 M. Nameplate Soler 3 e 1,458 743% 1 350 22 46 2017 /18 1,066 (10) (3) 1,063 0 0.955 1.090 1,159 0 1,159 1,432 0 DSM (2 WV) & 58.5 MW Biomass & 1 MW Solar 51 1,519 7.43% 1,906 167 247 2018 /19 1,069 (11) (5) 1,064 0 0.955 1.090 1,160 ❑ 1,160 1,438 0 0551(1 MVV)& 1 MN Nameplate Solar 1 * 1,526 742% 1,413 171 253 2019 /20 1,072 (121 (7) 1,065 0 0,955 1.090 1,161 0 1,161 1,438 0 DWI (2 NW) & 1 MW Nameplate Solar 3 ' 1,529 742% 1,416 170 255 2020 /21 1,074 (12) (9) 1,065 ❑ 0.955 1,090 1,162 0 1,162 1,443 0 DSM (5 NW) & 12 WV Nameplate Solar 10 ' 1,544 742% 1,429 174 267 2021 /22 1,081 (13) (10) 1,071 0 0.955 1,090 1,167 0 1,167 1,443 0 DSM (6 MW) & 12 MW Nameplate Solar 11 ' 1,555 7.42% 1,440 169 273 2022 /23 1,086 (13) (11) 1,075 0 0.955 1.090 1,172 0 1,172 1,443 0 13 MW Nameplate Solar 5 ' 1,560 742% 1,444 169 272 2023 /24 1,088 (14) (12) 1,677 0 0.955 1.090 1,174 0 1,174 1,443 0 DSM (1 MW) & 13 WV Nameplate Solar 6 . 1,566 7.42% 1,450 , 162 276 2024 /25 1,090 (14) (12) 1,078 0 0.955 1.090 1,175 ❑ 1,175 1,443 0 DSM (4 MW) & 13W/ Nameplate Solar 10 ' 1,576 7,42% 1,459 161 254 2025 /25 1,097 (14) (13) 1,084 0 0,955 1.090 1,182 0 1,182 1,440 0 DSM (2 )NV/8 14 WV Nameplate Solar 7 ' 1,580 7.42% 1,463 151 281 2026 /27 1,102 (14) (13) 1,088 0 0.955 1.090 1,186 0 1,186 1,440 0 DSM (2 MW) & 15 NM/ Nameplate Solar a ' 1,589 742% 1,471 147 285 2027 /28 1,107 (14) (14) 1,093 0 0.955 1.090 1,192 0 1,192 1,440 0 OSM (2 MW) & 17 WV Nameplate Solar 9 . 1,598 7.42% 1,479 141 287 2028 129 1,109 (14) 14) 1,096 0 0.955 1 090 1,195 0 1,195 1 438 0 DSM(-5 MW) & 18 MW Nameplate Solar 3 1,599 742% 1.480 136 285

Notes (a) Based on (July 2013) Load Forecast (vath implied PJM diversity factor)

(b) Existing plts approved and projected "Passive" EE, and VVO (note: these values & timing are for reference oNy and are not reflected in position determination)

(c) For PJM planning purposes, the ultimate impact of new DSM is 'delayed' -4 years to represent the ultimate recognition of these amounts through the PJM-originated load forecast process

(d) Demand Response approved by PJM in the prior planning year pl. forecasted "Active" DR

(0) installed Reserve Margin (IRM) = 15.6%(2012), 15.9%(2013-2014), 15 3%(2015), 156%(2016-2030) Forecast Pool Requirement (PPR). (1 k- IRM) • (1 -PJM EFORd)

(f) Includes company MLR share oh FRR view of obligations only

(g) Reflects the members ovmership ratio of foilowing summer capability assumptions: Wind Farm PPAs (Where Applicable)

(5) continued EFFICIENCY IMPROVEMENTS:

2018/19: Rockport 1'. 36 MW (turbine) 2020/21: Rockport 2:36 MW (turbine)

POD DERATES: 2025/26: Rockport 1: 18 MW 2028/29: Rockport 2: 18 MW

DSI DERATES: 2014/15: Rockport 1-2: 0 MW each

GAS CONVERSION BERATES: 2016(17: Big Sandy 1: (18) MW

RETIREMENTS: 2015/16: Big Sandy 2 2025/26: Big Sandy 1

(h) Includes company's share oh CeredolDerby/Glen Lyn Sale to AMPO,ATSI, and IMEA 2012/13 (171 MW) Sale of 12 MW 102012/13 and 13 MW in 2013/14 to Duke Sale 01210 MW 2012/13 to EMMT RPM Auction Sales 2012/13 - 2013/14 (646, 700)(MVV UCAP) 3.6 MVV capacity credit from SEPA's Philpot Dam via Blue Ridge contract

Plus: Estimated l&M nominations for PJM EE ('passive' DR program) levels -reflected as a UCAP part of Rim's emerging

auction products (eft, 2014/15)

(i) Newvrind and solar capacity value is assumed to be 13% and 38% of namepls

(1) Beginning 2008109, based on 12-month avg. AEP EFORd in eCapacity as of twelve months ended 9/30 of the previous year

(It) Actual PJM forecast

71 Combustion Turbines (CT) added to maintain Black Stan capability

Elective 1-1-2014, remaining capacity that was previously MLR'd will be allocated as folio.:

1) SEPA =>100% to APCo

188


Exhibit 4-13 (807 KAR 5:058 Sec.8.3.b.1-11. and Sec. 8.3.c. and Sec. 8.4.a.)

Final CLR Winter View KENTUCKY POWER COMPANY

Projected Winter Peak Demands, Generating Capabilities, and Margins (ICAP) Based on (July 2013) Load Forecast

(2012/2013 - 2028/2029) Final

(1) (2) (3) (4) (5)

16) (7)

(8) (9)

(10) (11) (12) (13)

(14) (15) 116) (17)

7(9)-(98 0(13)-(5) =m(1(5r -Too 113)-(7) x.(10)/(7)•100 ,Surn(1-4)

=Sum(5-6) +suri(11).(12)

Peak Demand - MW Winter

Season Internal Internal DSM (b) Committed Net Demand (interruptible Total

Demand (a) Wholesale Sales (c) Demand Demand Contracts

2011/12 Actual 1,378 0 1,378 1,378 2012/13 Actual 1,409 0 1,409 1,409' 2013/14 1,440 (0 ) 1,432 1,432 2014/15 1,442 (11) 1,431 1,431 2015/16 1,445 (13) 1,432 1,432 2016/17 1,448 (15) 1,431 1,431 2017/18 1,448 (17) 1,431 1,431 2018/19 1,450 lie) 1,432 1,432 2019/20 1.449 (19) 1,430 1.430 2020/21 1,458 (20) 1,435 1,435 2021/22 1,460 1211 1,439 1;439 2022723 1,459 121) 1,438 1.438 2023/24 1,459 (21) 1,438 1,435 2024725 1,485 (21) 1.444 1.444 2025726 1,459 (21) 1,448 1,448 2026/27 1.473 (21) 1,452 1,452 2027/28 1,475 (21) 1,454 1,454 2028/29 1,480 (21) 1,459 1.459

Capacity -MW Existing Committed Annual Total Capacity

Capacity& Net Sales Purchases Planned (0)

Changes (d) Planned Capacity Additions Units MW (I)

1,471 9 1,382 1,471 8 1,413 1,471 1 1,430 2251 DSM (5 MW) 7 2258 1,433 DSM (2 MIN) & 100 WV Nameplate WMd 16 r 1,456 1,433 DSM (2 WV) & 3 MW Nameplate Solar 2 1.458 1,438 DSM (2 MW) & 58.5 MW Biomass & 1 MW Solar 60 r 1,523 1,438 0014(1 MI & 1 WV Nameplate Solar 1 r 1,524 1,444 OSM (2 MW) & 1 WV Nameplate Solar 3 1,533 1,444 DSM (5 MW) 612 MW Nameplate Solar 6 1.539 1,444 DSM (6 MVO& 12 NW Nameplate Solar 7 1,546 1,444 13 W/ Nameplate Solar 1 1,547 1,444 DSM (1 MN) 613 MW Nameplate Solar 1 1,549 1,444 0514 (4 MIN) & 13 MW Nameplate Solar 5 1,554 1,441 DSM (2 WV) & 14 MW Nameplate Solar 3 - 1,554 1,441 DSM (2 NW) & 15 MW Nameplate Solar 3 1,557 1,441 DSM (2 MvV) & 17 MW Nameplate Solar 4 1,561 1,438 DSM (.5 MW) 610 MW Nameplate Solar (3) 1,554

Reserve Margin - MW

Reserve %of Internal Reserve % of Internal Margin Demand Margin After Demand Before Interruptible

interruptible

4 0,30 4 0,30 4 0.30 4 an (2) (0,10) (2) (0.10)

627 57 50 527 57.80 24 1 70 24 170

27 1.90 27 1,90 92 6,40 92 6.40 92 6.40 92 6A0

103 7,20 103 7.20 103 7.20 103 7.20

107 7.90 107 7.90 109 7.60 109 7.60 111 770 111 7.70 110 7.60 110 7E0 106 720 106 7.30 105 7,20 105 7.20 107 740 107 740 95 6 50 95 6 50

Notes: (a )'Based on (July 2013) Load Forecast (not coincident WM PJM's peak)

(b) Existing plus approved and projected "Passive" EE, and VVO

(c) Includes companies MLR share of

(d) Reflects the following Winter capability assumptions:

Wind Farm PPA5 (Where Applicable)

EFFICIENCY IMPROVEMENTS:

2017/18, Rockp oat: 36 MW (turbine)

2019/20: Rockport 2:36 MW (turbine)

(d) continued

POD DERATES:

2025/26, Rockport 1: 18 MW

2028/29: Rockport 2: 18 MW

OSI BERATES:

2015/16: Rockport 1-2: 0 MW each

GAS CONVERSION RERATES:

2016/17: Big Sandy 1: (18(14W

RETIREMENTS:

2015/16: Big Sandy 2

202526: Big Sandy 1

(e) Includes company's share oL

Contractual share of remaining Mane capacity

Ceredo/Darby/Glen Lyn Sale to AMPO,ATSI, and IMEA 2012/13 (171 MW)

Sale of 12 MW in 2012/13 and 13 MW in 2013/14 to Duke Sale o(210 MW 2012/13 to EMMT

RPM Auction Sales 2012/13 - 2013/14 (646, 700)(MW UCAP)

3.9 MW capacity credit hem SEPA's Philpot Dam via Blue Ridge contract

(I) New wind and solar capacity value is assumed to be 13% and 6.67% of nameplate

(*) Combustion Turbines (CT) added to maintain Black Start capability

Effective 1-1-2014, remaining capacity that was prevlouslyMLR'd will be allocated

as follows:

1)Remaining Merle Share 100% to OPCo 2) SEPA =>100% to APCo

189

KEN CKY 1301/1 A unit of American Electric Power


Exhibit 4-14 (807 KAR 5:058 Sec. 8.4.b.and c.)

KENTUCKY POWER COMPANY Annual Internal Energy Requirements, Energy Resources and Energy Inputs

2014 - 2028

Load and Energy Efficiency (GWh) Energy Resources (GWh)

Energy Inputs (By Primary Fuel Type)

Year

Energy Requirements (GWh) Generation (By Primary Fuel Type) Renewables/Purchases Coal-fired Generation Gas-fired Generation Base Forecast Internal Energy Energy Adjusted Requirements Efficiency(A) Energy Coal Gas Total

Utility Solar(B)

Distributed Solar Wind Total(C) Tons (000) MMBtu (000) MCF (000) MMBtu(000)

2014 6,751 (29) 6,722 7,381 0 7,381 0 0 0 7,381 3,286 73,395 0 0 2015 6,746 (38) 6,708 6,693 0 6,693 0 0 294 6,987 2,947 66,117 0 0 2016 6,763 (48) 6,715 7,028 77 7,104 0 2 294 7,399 3,134 69,086 890 912 2017 6,768 (58) 6,709 7,066 101 7,167 0 2 294 7,462 3,137 69,252 1,171 1,200 2018 6,771 (68) 6,703 7,003 109 7,113 0 3 294 7,409 3,105 68,594 1,262 1,294 2019 6,778 (78) 6,700 6,861 105 6,966 0 3 294 7,263 3,010 66,703 1,218 1,248 2020 6,789 (88) 6,701 6,859 96 6,956 23 4 294 7,276 2,992 67,010 1,120 1,148 2021 6,803 (121) 6,683 6,660 111 6,771 45 5 294 7,114 2,912 65,055 1,287 1,319 2022 6,827 (131) 6,696 5,895 64 5,959 68 7 294 6,326 2,551 57,553 737 755 2023 6,847 (140) 6,707 6,050 46 6,096 90 8 294 6,488 2,631 59,205 537 550 2024 6,862 (147) 6,715 6,016 45 6,061 113 10 294 6,478 2,622 58,867 530 543 2025 6,879 (152) 6,727 6,084 51 6,135 135 13 294 6,576 2,621 59,367 600 615 2026 6,900 (156) 6,744 6,763 72 6,834 158 16 294 7,301 2,946 65,936 833 854 2027 6,922 (160) 6,762 6,738 39 6,777 180 20 294 7,270 2,948 65,701 454 465 2028 6,945 (163) 6,782 6,507 94 6,601 204 25 294 7,123 2,809 63,384 1,090 1,117

Notes: (A) Represents incremental EE and VVO. (B) Contracted purchased solar energy amounts (C) Sum of Kentucky Power generated energy, energy purchased from other utilities, and wind purchases

190

7,11; MICKY 00w 1 VER


Exhibit 4-15 (807 KAR 5:058 Sec.6)

Comparison of 2009 and 2013 Capacity Expansion Plans

2009 IRP 2013 IRP Big Sandy Unit 1 Big Sandy Unit 2

Retire Retrofit

Gas conversion Retire

Mitchell Unit 1 Mitchell Unit 2

Part of the AEP-East Pool Part of the AEP-East Pool

50% Transfer 50% Transfer

New Capacity Additions

- Added solar starting in 2011

-Adds utility-scale solar beginning in 2020

- Adds distributed solar beginning in 2016 -Assumes additions of 100 MW Wind starting in 2015 - Implements customer and grid energy efficiency programs - Assumes addition of 58.5 MW biomass from ecoPower

191

MEI !MY {21'1

A IL ,Li1 L • ?rican Electric Power


Confidential Exhibit 4-16 (807 KAR 5:058 Sec.8.3.a.)

See Confidential Exhibit 4-16, the AEP System-East Zone, Transmission Facilities map provided in the Confidential Supplement to this filing.


AEP System-East Zone, Transmission Facilities Map

CONFIDENTIAL INFORMATION REDACTED

192

/MY



Confidential Exhibit 4-17 (807 KAR 5:058 Sec.8.3.a.)

See Confidential Exhibit 4-17, the AEP Transmission Line Network — Kentucky map provided in the Confidential Supplement to this filing.


AEP Transmission Line Network — Kentucky Map

CONFIDENTIAL INFO ATION REDACTED

193


Exhibit 4-18 (807 KAR 5:058 Sec.5.4.)

AEP External Ties located in Kentucky

From To Voltage (kV)

Interchange Rating (MVA)

Normal/Emergency Summer Winter

Duke Energy Midwest (DEM) (Formerly Cinergy, Formerly CG&E) Tanners Creek (AEP/I&M) East Bend 345 1195/13151 1195/1315

East Kentucky Power Cooperative (EKPC) Millbrook Park (AEP/OPC) Argentum 138 205/215 215/215

Falcon (AEP/KPC) Falcon 69 35/35 35/35 Grays Branch (AEP/KPC) Argentum 69 39/46 54/58

Grayson (AEP/KPC) Grayson 69 20/20 20/20 Leon (AEP/KPC) Leon 69 54/54 54/54

Pelfrey (AEP/KPC) Pelfrey 69 19/19 49/49 Thelma (AEP/KPC) Thelma 69 78/96 103/106 Salt Lick (AEP/KPC) Salt Lick 46 38/46 52/58

Total 488/531 582/595

E.ON US (LGEE) (Formerly LG&E Formerly KU) 161 138

Wooten (AEP/KPC) Hillsboro (AEP/OPC)

Hyden Kenton

300/404 159/191

379/418 191/191

Morehead (AEP/KPC) Rodburn (Morehead) 69 69/72 72/72 Total 528/667 642/681

Tennesee Valley Authorit (TVA) Leslie (AEP/KPC) Pineville 161 I 216/249 I 289/330

194

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